Cover Page
Cover Page | 12 Months Ended |
Dec. 31, 2023 shares | |
Cover [Abstract] | |
Entity Central Index Key | 0001127248 |
Document Type | 40-F |
Document Registration Statement | false |
Document Annual Report | true |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2023 |
Document Fiscal Period Focus | FY |
Document Fiscal Year Focus | 2023 |
Current Fiscal Year End Date | --12-31 |
Entity File Number | 000-54516 |
Entity Registrant Name | EMERA INCORPORATED |
Entity Incorporation, State or Country Code | A5 |
Entity Listings [Line Items] | |
Entity Address, Address Line One | 5151 Terminal Road |
Entity Address, City or Town | Halifax |
Entity Address, State or Province | NS |
Entity Address, Country | CA |
Entity Address, Postal Zip Code | B3J 1A1 |
City Area Code | 902 |
Local Phone Number | 428-6096 |
Annual Information Form | true |
Audited Annual Financial Statements | true |
Document Fin Stmt Error Correction Flag | false |
Entity Current Reporting Status | No |
Entity Interactive Data Current | Yes |
Entity Emerging Growth Company | false |
ICFR Auditor | false |
Auditor Name | Ernst & Young LLP |
Auditor Location | Halifax, Canada |
Auditor Firm Id | 1263 |
Business Contact [Member] | |
Entity Listings [Line Items] | |
Contact Personnel Name | Emera US Finance LP |
Entity Address, Address Line One | c/o Corporation Service Company |
Entity Address Address Line Two | 251 Little Falls Drive |
Entity Address, City or Town | Wilmington |
Entity Address, State or Province | DE |
Entity Address, Postal Zip Code | 19808 |
City Area Code | 302 |
Local Phone Number | 636-5401 |
Common Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 284,117,511 |
Series A Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 4,866,814 |
Series B Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 1,133,186 |
Series C Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 10,000,000 |
Series E Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 5,000,000 |
Series F Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Series H Preferred Stock | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 12,000,000 |
Series J Preferred Stock [Member] | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 8,000,000 |
Series L Preferred Stock [Member] | |
Entity Listings [Line Items] | |
Entity Common Stock, Shares Outstanding | 9,000,000 |
Consolidated Statements of Inco
Consolidated Statements of Income - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Operating revenues | ||
Total operating revenues (note 5) | $ 7,563 | $ 7,588 |
Operating expenses | ||
Operating, maintenance and general expenses ("OM&G") | 1,879 | 1,596 |
Provincial, state, and municipal taxes | 433 | 367 |
Depreciation and amortization | 1,049 | 952 |
GBPC Impairment charge (note 22) | 0 | 73 |
Total operating expenses | 5,769 | 5,959 |
Income from operations | 1,794 | 1,629 |
Income from equity investments (note 7) | 146 | 129 |
Other income, net (note 8) | 158 | 145 |
Interest expense, net (note 9) | (925) | (709) |
Income before provision for income taxes | 1,173 | 1,194 |
Income tax expense (note 10) | 128 | 185 |
Net income | 1,045 | 1,009 |
Non-controlling interest in subsidiaries | 1 | 1 |
Preferred stock dividends | 66 | 63 |
Net income attributable to common shareholders | $ 977.7 | $ 945.1 |
Earnings per common share (note 12) | ||
Basic | $ 3.57 | $ 3.56 |
Diluted | $ 3.57 | $ 3.55 |
Weighted average shares of common stock outstanding (in millions) (note 12) | ||
Basic | 273.6 | 265.5 |
Diluted | 273.8 | 265.9 |
Dividends per common share declared | $ 2.7875 | $ 2.6775 |
Regulated | Gas Revenue | ||
Operating revenues | ||
Total operating revenues (note 5) | $ 1,489 | $ 1,681 |
Operating expenses | ||
Fuel for generation and purchased power | 527 | 800 |
Regulated | Electric Revenue | ||
Operating revenues | ||
Total operating revenues (note 5) | 5,746 | 5,473 |
Operating expenses | ||
Fuel for generation and purchased power | 1,881 | 2,171 |
Non-Regulated | ||
Operating revenues | ||
Total operating revenues (note 5) | $ 328 | $ 434 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Consolidated Statements of Comprehensive Income | ||
Net income | $ 1,045 | $ 1,009 |
Other comprehensive (loss) income, net of tax | ||
Foreign currency translation adjustment | (270) | 629 |
Unrealized gains (losses) on net investment hedges | 38 | (97) |
Cash flow hedges - reclassification adjustment for gains included in income | (2) | (2) |
Cash flow hedges | ||
Unrealized losses on available-for-sale investment | 0 | (1) |
Net change in unrecognized pension and post-retirement benefit obligation | (39) | 24 |
Other comprehensive (loss) income | (273) | 553 |
Comprehensive income | 772 | 1,562 |
Comprehensive income attributable to non-controlling interest | 1 | 1 |
Comprehensive Income of Emera Incorporated | $ 771 | $ 1,561 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Foreign currency translation, tax expense (recovery) | $ (7) | $ 7 |
Hybrid Notes as a hedge of the foreign currency exposure | 1,200 | 1,100 |
Unrealized gains (losses) on net investment hedges | 0 | (6) |
Net derivative gain, tax | 0 | (1) |
Net change in unrecognized pension and post-retirement benefit obligation | 1 | 1 |
Other comprehensive loss, Tax | (6) | $ 1 |
Net investment in United States dollar denominated operations | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,200 |
Consolidated Balance Sheets
Consolidated Balance Sheets - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Current assets | ||
Cash and cash equivalents | $ 567 | $ 310 |
Restricted cash (note 32) | 21 | 22 |
Inventory (note 14) | 790 | 769 |
Derivative instruments (notes 15 and 16) | 174 | 296 |
Regulatory assets (note 6) | 339 | 602 |
Receivables and other current assets (note 18) | 1,817 | 2,897 |
Total current assets | 3,708 | 4,896 |
Property, plant and equipment ("PP&E"), net of accumulated depreciation and amortization of $9,994 and $9,574, respectively (note 20) | 24,376 | 22,996 |
Other assets | ||
Deferred income taxes (note 10) | 208 | 237 |
Derivative instruments (notes 15 and 16) | 66 | 100 |
Regulatory assets (note 6) | 2,766 | 3,018 |
Net investment in direct finance and sales type leases (note 19) | 621 | 604 |
Investments subject to significant influence (note 7) | 1,402 | 1,418 |
Goodwill (note 22) | 5,871 | 6,012 |
Other long-term assets (note 32) | 462 | 461 |
Total other assets | 11,396 | 11,850 |
Total assets | 39,480 | 39,742 |
Current liabilities | ||
Short-term debt (note 23) | 1,433 | 2,726 |
Current portion of long-term debt (note 25) | 676 | 574 |
Accounts payable | 1,454 | 2,025 |
Derivative instruments (notes 15 and 16) | 386 | 888 |
Regulatory liabilities (note 6) | 168 | 495 |
Other current liabilities (note 24) | 427 | 579 |
Total current liabilities | 4,544 | 7,287 |
Long-term liabilities | ||
Long-term debt (note 25) | 17,689 | 15,744 |
Deferred income taxes (note 10) | 2,352 | 2,196 |
Derivative instruments (notes 15 and 16) | 118 | 190 |
Regulatory liabilities (note 6) | 1,604 | 1,778 |
Pension and post-retirement liabilities (note 21) | 265 | 281 |
Other long-term liabilities (notes 7 and 26) | 820 | 825 |
Total long-term liabilities | 22,848 | 21,014 |
Equity | ||
Common stock (note 11) | 8,462 | 7,762 |
Cumulative preferred stock (note 28) | 1,422 | 1,422 |
Contributed surplus | 82 | 81 |
Accumulated other comprehensive income ("AOCI") (note 13) | 305 | 578 |
Retained earnings | 1,803 | 1,584 |
Total Emera Incorporated equity | 12,074 | 11,427 |
Non-controlling interest in subsidiaries (note 29) | 14 | 14 |
Total equity | 12,088 | 11,441 |
Total liabilities and equity | $ 39,480 | $ 39,742 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Consolidated Balance Sheets | ||
Accumulated depreciation and amortization on property, plant and equipment | $ 9,994 | $ 9,574 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Operating activities | ||
Net income | $ 1,045 | $ 1,009 |
Adjustments to reconcile net income to net cash provided by operating activities: | ||
Depreciation and amortization | 1,060 | 959 |
Income from equity investments, net of dividends | (22) | (61) |
Allowance for funds used during construction ("AFUDC") - equity | (38) | (52) |
Deferred income taxes, net | 97 | 152 |
Net change in pension and post-retirement liabilities | (68) | (48) |
NSPI Fuel adjustment mechanism ("FAM") | (88) | (162) |
Net change in Fair Value ("FV") of derivative instruments | (666) | 206 |
Net change in regulatory assets and liabilities | 554 | (471) |
Net change in capitalized transportation capacity | 434 | (445) |
GBPC Impairment charge | 0 | 73 |
Other operating activities, net | 28 | (13) |
Changes in non-cash working capital (note 30) | (95) | (234) |
Net cash provided by operating activities | 2,241 | 913 |
Investing activities | ||
Additions to PP&E | (2,937) | (2,596) |
Other investing activities | 20 | 27 |
Net cash used in investing activities | (2,917) | (2,569) |
Financing activities | ||
Change in short-term debt, net | (66) | 1,028 |
Proceeds from short-term debt with maturities greater than 90 days | 548 | 544 |
Repayment of short-term debt with maturities greater than 90 days | (1,086) | (680) |
Proceeds from long-term debt, net of issuance costs | 1,932 | 784 |
Retirement of long-term debt | (151) | (367) |
Net (repayments) proceeds under committed credit facilities | (96) | 511 |
Issuance of common stock, net of issuance costs | 424 | 277 |
Dividends on common stock | (488) | (472) |
Dividends on preferred stock | (66) | (63) |
Other financing activities | (12) | (7) |
Net cash provided by financing activities | 939 | 1,555 |
Effect of exchange rate changes on cash, cash equivalents, and restricted cash | (7) | 16 |
Net increase (decrease) in cash, cash equivalents, and restricted cash | 256 | (85) |
Cash, cash equivalents, and restricted cash, beginning of year | 332 | 417 |
Cash, cash equivalents, and restricted cash, end of year | $ 588 | $ 332 |
Consolidated Statements of Ca_2
Consolidated Statements of Cash Flows (Parenthetical) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Cash, cash equivalents and restricted cash consists of: | ||
Cash | $ 559 | $ 302 |
Short-term investments | 8 | 8 |
Restricted cash | 21 | 22 |
Cash, cash equivalents, and restricted cash | $ 588 | $ 332 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Equity - CAD ($) $ in Millions | Total | Common Stock [Member] | Preferred Stock | Contributed Surplus | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Non-Controlling Interest |
Beginning Balance at Dec. 31, 2021 | $ 10,150 | $ 7,242 | $ 1,422 | $ 79 | $ 25 | $ 1,348 | $ 34 |
Net income of Emera Inc. | 1,009 | 0 | 0 | 0 | 0 | 1,008 | 1 |
Other comprehensive income (loss), net of tax expense | 553 | 0 | 0 | 0 | 553 | 0 | 0 |
Dividends declared on preferred stock (note 28) | (63) | 0 | 0 | 0 | 0 | (63) | 0 |
Dividends declared on common stock | (709) | 0 | 0 | 0 | 0 | (709) | 0 |
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs | 248 | 248 | 0 | 0 | 0 | 0 | 0 |
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount | 238 | 238 | 0 | 0 | 0 | 0 | 0 |
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP") | 36 | 34 | 0 | 2 | 0 | 0 | 0 |
Disposal of non-controlling interest of Dominica Electricity Services Ltd ("Domlec") | (20) | 0 | 0 | 0 | 0 | 0 | (20) |
Other | (1) | 0 | 0 | 0 | 0 | 0 | (1) |
Ending Balance at Dec. 31, 2022 | 11,441 | 7,762 | 1,422 | 81 | 578 | 1,584 | 14 |
Net income of Emera Inc. | 1,045 | 0 | 0 | 0 | 0 | 1,044 | 1 |
Other comprehensive income (loss), net of tax expense | (273) | 0 | 0 | 0 | (273) | 0 | 0 |
Dividends declared on preferred stock (note 28) | (66) | 0 | 0 | 0 | 0 | (66) | 0 |
Dividends declared on common stock | (759) | 0 | 0 | 0 | 0 | (759) | 0 |
Issued under the at-the-market program ("ATM"), net of after-tax issuance costs | 397 | 397 | 0 | 0 | 0 | 0 | 0 |
Issued under the Dividend Reinvestment Program ("DRIP"), net of discount | 272 | 272 | 0 | 0 | 0 | 0 | 0 |
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP") | 32 | 31 | 0 | 1 | 0 | 0 | 0 |
Other | (1) | 0 | 0 | 0 | 0 | 0 | (1) |
Ending Balance at Dec. 31, 2023 | $ 12,088 | $ 8,462 | $ 1,422 | $ 82 | $ 305 | $ 1,803 | $ 14 |
Consolidated Statements of Ch_2
Consolidated Statements of Changes in Equity (Parenthetical) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Consolidated Statements of Changes in Equity | ||
Other comprehensive loss, tax expense/recovery | $ (6) | $ 1 |
Dividends per common share declared | $ 2.7875 | $ 2.6775 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Summary of Significant Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | 1. Nature of Operations Emera Incorporated (“Emera” or the “Company”) is an energy and services company which invests in electricity generation, transmission and distribution, and gas transmission and distribution. At December 31, 2023, Emera’s reportable segments include the following: ● electric utility, serving approximately 840,000 ● ● primary electricity supplier in Nova Scotia, serving approximately 549,000 ● investments related to an 824 Falls on the Lower Churchill River in Labrador, developed by Nalcor Energy. investments are: ● 100 the Maritime Link Project, a $ 1.8 ● 31 Partnership (“LIL”), a $ 3.7 Labrador. ● ● 490,000 to be a division of Tampa separate legal entity called Peoples Gas System Inc., a wholly owned direct subsidiary of TECO Gas Operations, Inc.; ● approximately 540,000 ● 145 -kilometre pipeline delivering re-gasified liquefied natural gas from Saint John, New Brunswick to the United States border under a 25 -year firm service agreement with Repsol Energy North America Canada Partnership (“Repsol Energy”), which expires in 2034; ● transmission company offering services in Florida; and ● 12.9 1,400 -kilometre pipeline that transports natural gas throughout markets in Atlantic Canada and the northeastern United States. ● with regulated electric utilities that include: ● electric utility on the island of Barbados, serving approximately 134,000 ● utility on Grand Bahama Island, serving approximately 19,000 ● 19.5 integrated regulated electric utility on the island of St. Lucia. ● which include: ● ● natural gas and electricity and provides related energy asset management services; ● 30 electricity facility in Brooklyn, Nova Scotia; and ● 50.0 Swamp”), a 660 Massachusetts. ● financing subsidiaries of Emera; ● company focused on finding ways to deliver renewable and resilient energy to customers; ● located in the United States; and ● Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated. Principles of Consolidation These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the VIE that most significantly impacts its economic performance and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction. Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 6. Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”). Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulators and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes. Non-regulated Revenue: Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of the contract are satisfied and are presented on a net basis reflecting the nature of contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. PP&E PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units, are included in “PP&E” on the Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”). Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs a qualitative assessment and determines it is more likely than not that its FV is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss is recorded. Management estimates the FV of the reporting unit by using the income approach, or a combination of the income and market approach. The income approach uses a discounted cash flow analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. For the market approach, management estimates FV based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting unit using an income approach include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2023, $ 5,868 purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result, no impairment charges were recognized. In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment charge of $ 73 nil details, refer to note 22. Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred income tax assets will be recovered from future taxable income is assessed and assumptions are made about the expected timing of reversal of deferred income tax assets and liabilities. If management subsequently determines it is likely that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable, except for the deferred income taxes on certain regulatory balances specifically prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10. Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as HFT. Collectively, derivatives. The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31, 2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues, fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”. Leases The Company determines whether a contract contains a lease at inception by evaluating whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to purchase wind and hydro energy over varying contract lengths which are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the difference between the FV and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates the weighted-average cost will be recovered in future customer rates. Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long- lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2023 or 2022. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at FV, with changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required in either 2023 or 2022. Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs that are not recognized in the consolidated financial statements, as the FV of these obligations could not be reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at FV in the period in which an amount can be determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock- based compensation cost is measured at the grant date, based on the calculated FV of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV and re-measured at FV at each reporting date, with the change in liability recognized in income. Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes |
Future Accounting Pronouncement
Future Accounting Pronouncements | 12 Months Ended |
Dec. 31, 2023 | |
Future Accounting Pronouncements [Abstract] | |
Future Accounting Pronouncements | 2. The Company considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board (“FASB”). The following updates have been issued by the FASB, but as allowed, have not yet been adopted by Emera. Any ASUs not included below were assessed and determined to be either not applicable to the Company or to have an insignificant impact on the consolidated financial statements. Improvements to Income Tax Disclosures In December 2023, the FASB issued ASU 2023-09, Income Taxes Tax income tax disclosures by requiring consistent categories and greater disaggregation of information in the reconciliation of income taxes computed using the enacted statutory income tax rate to the actual income tax provision and effective income tax rate, as well as the disaggregation of income taxes paid (refunded) by jurisdiction. The standard also requires disclosure of income (loss) before provision for income taxes and income tax expense (recovery) in accordance with U.S. Securities and Exchange Commission Regulation S-X 210.4-08(h), Rules of General Application – General Notes to Financial Statements: Income Tax The guidance will be effective for annual reporting periods beginning after December 15, 2024, and interim periods within annual reporting periods beginning after December 15, 2025. Early adoption is permitted. The standard will be applied on a prospective basis, with retrospective application permitted. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements. Improvements to Reportable Segment Disclosures In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic Reportable Segment Disclosures. The change in the standard improves reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. The changes improve financial reporting by requiring disclosure of incremental segment information on an annual and interim basis for all public entities to enable investors to develop more decision-useful financial analyses. The guidance will be effective for annual reporting periods beginning after December 15, 2023, and for interim periods beginning after December 15, 2024. Early adoption is permitted. The standard will be applied retrospectively. The Company is currently evaluating the impact of adoption of the standard on its consolidated financial statements. |
Dispositions
Dispositions | 12 Months Ended |
Dec. 31, 2023 | |
Dispositions [Abstract] | |
Dispositions | 3. DISPOSITIONS On March 31, 2022, Emera completed the sale of its 51.9 approximated its carrying value. Domlec was included in the Company’s Other Electric reportable segment up to its date of sale. The sale did not have a material impact on earnings. |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Information | 4. Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 95 December 31, 2023, between the Florida Electric Utility, Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expenses), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 GBPC impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2023 2022 United States 5,310 $ 5,346 Canada 1,727 1,725 Barbados 389 384 The Bahamas 137 122 Dominica - 11 $ 7,563 $ 7,588 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2023 2022 United States $ 18,588 $ 17,382 Canada 4,878 4,689 Barbados 576 583 The Bahamas 334 342 $ 24,376 $ 22,996 |
Revenue
Revenue | 12 Months Ended |
Dec. 31, 2023 | |
Revenue [Abstract] | |
Revenue | 5. The following disaggregates the Company’s revenue by major source: Electric Gas Other Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) $ 7,235 Non-Regulated Revenue Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) $ 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other electric 398 28 6 - - - 432 Regulatory deferrals (27) - 6 - - - (21) Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) 7,154 Non-Regulated Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 (1) Other includes rental revenues, which do not represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts customers. Remaining Performance Obligations: Remaining performance obligations primarily represent gas transportation contracts, lighting contracts, and long-term steam supply arrangements with fixed contract terms. As of December 31, 2023, the aggregate amount of the transaction price allocated to remaining performance obligations was $ 488 million (2022 – $ 450 134 to a gas transportation contract between SeaCoast and PGS through 2040 . This amount excludes contracts with an original expected length of one year or less and variable amounts for which Emera recognizes revenue at the amount to which it has the right to invoice for services performed. Emera expects to recognize revenue for the remaining performance obligations through 2043 . |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Regulatory Assets and Liabilities [Abstract] | |
Regulatory Assets and Liabilities | 6. REGULATORY Regulatory assets represent prudently incurred costs that have been deferred because it is probable they will be recovered through future rates or tolls collected from customers. Management believes existing regulatory assets are probable for recovery either because the Company received specific approval from the applicable regulator, or due to regulatory precedent established for similar circumstances. If management no longer considers it probable that an asset will be recovered, deferred costs are charged to income. Regulatory liabilities represent obligations to make refunds to customers or to reduce future revenues for previous collections. If management no longer considers it probable that a liability will be settled, the related amount is recognized in income. For regulatory assets and liabilities that are amortized, the amortization is as approved by the respective regulator. As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 Deferred Income Tax Regulatory Assets and Liabilities To years, a regulatory asset or liability is recognized as appropriate. TEC Capital Cost Recovery for Early Retired Assets This regulatory asset is related to the remaining net book value of Big Bend Power Station Units 1 through 3 and smart meter assets that were retired. The balance earns a rate of return as permitted by the FPSC and is recovered as a separate line item on customer bills for a period of 15 years . This recovery mechanism is authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. For further information, refer to “Big Bend Modernization Project” in the TEC section below. NSPI FAM NSPI has a FAM, approved by the UARB, allowing NSPI to recover fluctuating fuel and certain fuel- related costs from customers through regularly scheduled fuel rate adjustments. Differences between prudently incurred fuel costs and amounts recovered from customers through electricity rates in a year are deferred to a FAM regulatory asset or liability and recovered from or returned to customers in subsequent periods. Pension and Post-Retirement Medical Plan This asset is primarily related to the deferred costs of pension and post-retirement benefits at TEC, PGS and NMGC. It is included in rate base and earns a rate of return as permitted by the FPSC and NMPRC, as applicable. It is amortized over the remaining service life of plan participants. Cost Recovery Clauses These assets and liabilities are related to TEC, PGS and NMGC clauses and riders. They are recovered or refunded through cost-recovery mechanisms approved by the FPSC or New Mexico Public Regulation Commission (“NMPRC”), as applicable, on a dollar-for-dollar basis in a subsequent period. Deferrals Related to Derivative Instruments This asset is primarily related to NSPI deferring changes in FV of derivatives that are documented as economic hedges or that do not qualify for NPNS exemption, as a regulatory asset or liability as approved by the UARB. The realized gain or loss is recognized when the hedged item settles in regulated fuel for generation and purchased power, other income, inventory, being economically hedged. Storm Cost Recovery Clauses TEC and PGS Storm Reserve: The storm reserve is for hurricanes and other named storms that cause significant damage to TEC and PGS systems. As allowed by the FPSC, if charges to the storm reserve exceed the storm liability, the excess is to be carried as a regulatory asset. TEC and PGS can petition the FPSC to seek recovery of restoration costs over a 12-month period or longer, as determined by the FPSC, as well as replenish the reserve. In 2022, TEC and PGS were impacted by Hurricane Ian. For further information, refer to “TEC Storm Reserve” in the Florida Electric Utility section below. NSPI Storm Rider: NSPI has a UARB approved storm rider for each of 2023, 2024 and 2025, which gives NSPI the option to apply to the UARB for recovery of costs if major storm restoration expenses exceed approximately $ 10 million in a given year. GBPC Storm Restoration: This asset represents storm restoration costs incurred by GBPC. GBPC maintains insurance for its generation facilities and, as with most utilities, its transmission and distribution networks are not covered by commercial insurance. In January 2020, the Grand Bahama Port Authority (“GBPA”) approved recovery of $ 15 2019 costs related to Hurricane Dorian, over a five-year period from 2021 through 2025. Restoration costs associated with Hurricane Matthew in 2016 are being recovered through an approved fuel charge. For further information, refer to “Storm Restoration Costs – Hurricane Matthew” in the GBPC section below. Environmental Remediations This asset is primarily related to PGS costs associated with environmental remediation at Manufactured Gas Plant sites. The balance is included in rate base, partially offsetting the related liability, and earns a rate of return as permitted by the FPSC. The timing of recovery is based on a settlement agreement approved by the FPSC. Stranded Cost Recovery Due to decommissioning of a GBPC steam turbine in 2012, the GBPA approved recovery of a $ 21 USD stranded cost through electricity rates; it is included in rate base and expected to be included in rates in future years. NMGC Winter Event Gas Cost Recovery In February 2021, the State of New Mexico experienced an extreme cold weather event that resulted in an incremental $ 108 NMGC normally recovers gas supply and related costs through a purchased gas adjustment clause (“PGAC”). On June 15, 2021, the NMPRC approved recovery of $ 108 costs in customer rates over a period of 30 months Accumulated Reserve – COR This regulatory liability represents the non-ARO COR reserve in TEC, PGS, NMGC and NSPI. AROs represent the FV of estimated cash flows associated with the Company’s legal obligation to retire its PP&E. Non-ARO COR represent estimated funds received from customers through depreciation rates to cover future COR of PP&E value upon retirement that are not legally required. This reduces rate base for ratemaking purposes. This liability is reduced as COR are incurred and increased as depreciation is recorded for existing assets and as new assets are put into service. NMGC Gas Hedge Settlements This regulatory liability represents regulatory deferral of gas options exercised above strike price but settled subsequent to the period end. The value from cash settlement of these options flows to customers via the PGAC. Other Regulatory Assets and Liabilities Comprised of regulatory assets and liabilities that are not individually significant. Regulatory Environments and Updates Florida Electric Utility TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. TEC’s approved regulated return on equity (“ROE”) range for 2023 and 2022 was 9.25 11.25 per cent based on an allowed equity capital structure of 54 10.20 10.20 Base Rates: On February 1, 2024, TEC notified the FPSC of its intent to seek a base rate increase effective January 2025, reflecting a revenue requirement increase of approximately $ 290 320 additional adjustments of approximately $ 100 70 respectively. TEC’s proposed rates include recovery of solar generation projects, energy storage capacity, a more resilient and modernized energy control center, and numerous other resiliency and reliability projects. The filing range amounts are estimates until TEC files its detailed case in April 2024. The FPSC is scheduled to hear the case in Q3 2024. On August 16, 2023, TEC filed a petition to implement the 2024 Generation Base Rate Adjustment provisions pursuant to the 2021 rate case settlement agreement. Inclusive of TEC’s ROE adjustment, the increase of $ 22 Fuel Recovery and Other Cost Recovery Clauses: TEC has a fuel recovery clause approved by the FPSC, allowing the opportunity to recover fluctuating fuel expenses from customers through annual fuel rate adjustments. The FPSC annually approves cost- recovery rates for purchased power, capacity, on capital invested. Differences between prudently incurred fuel costs and the cost-recovery rates and amounts recovered from customers through electricity rates in a year are deferred to a regulatory asset or liability and recovered from or returned to customers in subsequent periods. On January 23, 2023, TEC requested an adjustment to its fuel charges to recover the 2022 fuel under- recovery of $ 518 21 months . The request also included an adjustment to 2023 projected fuel costs to reflect the reduction in natural gas prices since September 2022 for a projected reduction of $ 170 FPSC on March 7, 2023, and were effective beginning on April 1, 2023. The mid-course fuel adjustment requested by TEC on January 19, 2022, was approved on March 1, 2022. The rate increase, effective with the first billing cycle in April 2022, covered higher fuel and capacity costs of $ 169 2022. Big Bend Modernization Project: TEC invested $ 876 91 modernize the Big Bend Power Station. The modernization project repowered Big Bend Unit 1 with natural gas combined-cycle technology and eliminated coal as this unit’s fuel. As part of the modernization project, TEC in 2020 retired the Unit 1 components that would not be used in the modernized plant and did the same for Big Bend Unit 2 in 2021. TEC retired Big Bend Unit 3 in 2023 as it was in the best interests of the customers from an economic, environmental risk and operational perspective. On December 31, 2021, the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, of $ 636 267 reclassified to a regulatory asset on the balance sheet. TEC’s 2021 settlement agreement provides for cost recovery of the Big Bend Modernization project in two phases. The first phase was a revenue increase to cover the costs of the assets in service during 2022, among other items. The remainder of the project costs were recovered as part of the 2023 subsequent year adjustment. The settlement agreement also includes a new charge to recover the remaining costs of the retired Big Bend coal generation assets, Units 1 through 3, which are spread over 15 years , effective January 1, 2022. This recovery mechanism was authorized by and survives the term of the settlement agreement approved by the FPSC in 2021. Storm Reserve: In September 2022, TEC was impacted by Hurricane Ian, with $ 119 charged against TEC’s FPSC approved storm reserve. Total restoration costs charged to the storm reserve exceeded the reserve balance and have been deferred as a regulatory asset for future recovery. On January 23, 2023, TEC petitioned the FPSC for recovery of the storm reserve regulatory asset and the replenishment of the balance in the storm reserve to the approved storm reserve level of $ 56 USD, for a total of $ 131 March 7, 2023, and TEC began applying the surcharge in April 2023. Subsequently, on November 9, 2023, the FPSC approved TEC’s petition, filed on August 16, 2023, to update the total storm cost collection to $ 134 29 million USD as of December 31, 2023, from over the first three months of 2024 to over the 12 months of 2024. The storm recovery is subject to review of the underlying costs for prudency and accuracy by the FPSC. In Q3 2023, TEC was impacted by Hurricane Idalia. The related storm restoration costs were approximately $ 35 minimal impact to earnings. Storm Protection Cost Recovery Clause and Settlement Agreement: The Storm Protection Plan (“SPP”) Cost Recovery Clause provides a process for Florida investor-owned utilities, including TEC, to recover transmission and distribution storm hardening costs for incremental activities not already included in base rates. Differences between prudently incurred clause-recoverable costs and amounts recovered from customers through electricity rates in a year are deferred and recovered from or returned to customers in a subsequent year. A settlement agreement was approved on August 10, 2020, and TEC’s cost recovery began in January 2021. The current approved plan addressed the years 2023, 2024 and 2025 and was approved by the FPSC on October 4, 2022. Canadian Electric Utilities NSPI NSPI is a public utility as defined in the Public Utilities Act of Nova Scotia (“Public Utilities Act”) and is subject to regulation under the Public Utilities Act by the UARB. The Public Utilities Act gives the UARB supervisory powers over NSPI’s operations and expenditures. Electricity rates for NSPI’s customers are also subject to UARB approval. NSPI is not subject to a general annual rate review process, but rather participates in hearings held from time to time at NSPI’s or the UARB’s request. NSPI is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers and provide a reasonable return to investors. NSPI’s approved regulated ROE range for 2023 and 2022 was 8.75 9.25 quarter average regulated common equity component of up to 40 General Rate Application (“GRA”): On February 2, 2023, the UARB approved the GRA settlement agreement between NSPI, key customer representatives and participating interest groups. This resulted in average customer rate increases of 6.9 per cent effective on February 2, 2023, and further average increases of 6.5 with any under or over-recovery of fuel costs addressed through the UARB’s established FAM process. It also established a storm rider and a demand-side management rider. On March 27, 2023, the UARB issued a final order approving the electricity rates effective on February 2, 2023. Fuel Recovery: For the period of 2020 through 2022, NSPI operated under a three-year fuel stability plan with no fuel rate adjustments related to the under-recovery of fuel and fuel-related costs in the period. On January 29, 2024, NSPI applied to the UARB for approval of a structure that would begin to recover the outstanding FAM balance. As part of the application, NSPI requested approval for the sale of $ 117 million of the FAM regulatory asset to Invest Nova Scotia, a provincial Crown corporation, with the proceeds paid to NSPI upon approval. NSPI has requested approval to collect from customers the amortization and financing costs of $ 117 10 -year period, and remit those amounts to Invest Nova Scotia as collected, reducing short-term customer rate increases relative to the currently established FAM process. If approved, this portion of the FAM regulatory asset would be removed from the Consolidated Balance Sheets and NSPI would collect the balance on behalf of Invest Nova Scotia in NSPI rates beginning in 2024. Storm Rider: The storm rider was effective as of the GRA decision date. The application for deferral and recovery of the storm rider is made in the year following the year of the incurred cost, with recovery beginning in the year after the application. Total major storm restoration expense for 2023 was $ 31 21 million was deferred to the storm rider. Hurricane Fiona: On October 31, 2023, NSPI submitted an application to the UARB to defer $ 24 operating costs incurred during Hurricane Fiona storm restoration efforts in September 2022. NSPI is seeking amortization of the costs over a period to be approved by the UARB during a future rate setting process. At December 31, 2023, the $ 24 approval. Maritime Link: The Maritime Link is a $ 1.8 two 170 -kilometre sub-sea cables, connecting the island of Newfoundland and Nova Scotia. The Maritime Link entered service on January 15, 2018 and NSPI started interim assessment payments to NSPML at that time. Any difference between the amounts recovered from customers through rates and those approved by the UARB through the NSPML interim assessment application will be addressed through the FAM. Nova Scotia Cap-and-Trade (“Cap-and-Trade”) As of December 31, 2022, the FAM included a cumulative $ 166 purchase of emissions credits and $ 6 March 16, 2023, the Province of Nova Scotia provided NSPI with emissions allowances sufficient to achieve compliance for the 2019 through 2022 period. As such, compliance costs accrued of $ 166 were reversed in Q1 2023. The credits NSPI purchased from provincial auctions in the amount of $ 6 million were not refunded and no further costs were incurred to achieve compliance with the Cap-and- Trade Program. Extra Large Industrial Active Demand Tariff: On July 5, 2023, NSPI received approval from the UARB to change the methodology in which fuel cost recovery from an industrial customer is calculated. Due to significant volatility in commodity prices in 2022, the previous methodology did not result in a reasonable determination of the fuel cost to serve this customer. The change in methodology, this industrial customer to the FAM. This adjustment was recorded in Q2 2023 resulting in a $ 51 increase to the FAM regulatory asset and an offsetting decrease to unbilled revenue within Receivables and other current assets. This adjustment had minimal impact on earnings. NSPML Equity earnings from the Maritime Link are dependent on the approved ROE and operational performance of NSPML. NSPML’s approved regulated ROE range is 8.75 9.25 based on an actual five-quarter average regulated common equity component of up to 30 Nalcor’s Nova Scotia Block (“NS Block”) delivery obligations commenced on August 15, 2021 and delivery will continue over the next 35 years In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 9 7 otherwise been recoverable if incurred by NSPI. On October 4, 2023 and January 31, 2024, the UARB issued decisions providing clarification on remaining aspects of the Maritime Link holdback mechanism primarily relating to release of past and future holdback amounts and requirements to end the holdback mechanism. In these decisions, the UARB agreed with the Company’s submission that $ 12 8 4 relating to 2023) of the previously recorded holdback remain credited to NSPI’s FAM, with the remainder released to NSPML and recorded in Emera’s “Income from equity investments. NSPML did not record any additional holdback in Q4 2023. The UARB also confirmed that the holdback mechanism will cease once 90 relief for planned outages or exceptional circumstances) and the net outstanding balance of previously underdelivered NS Block energy is less than 10 UARB increased the monthly holdback amount from $ 2 4 On December 21, 2023, NSPML received approval to collect up to $ 164 164 from NSPI for the recovery of costs associated with the Maritime Link in 2024; subject to a holdback of up to $ 4 Gas Utilities and Infrastructure PGS PGS is regulated by the FPSC. The FPSC sets rates at a level that allows utilities such as PGS to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. PGS’s approved ROE range for 2023 and 2022 was 8.9 11.0 9.9 midpoint, based on an allowed equity capital structure of 54.7 Base Rates: On April 4, 2023, PGS filed a rate case with the FPSC and a hearing for the matter was held in September 2023. On November 9, 2023, the FPSC approved a $ 118 revenues which includes $ 11 for a net incremental increase to base revenues of $ 107 10.15 midpoint ROE with an allowed equity capital structure of 54.7 December 27, 2023, with the new rates effective January 2024. The 2020 PGS rate case settlement provided the ability to reverse a total of $ 34 accumulated depreciation through 2023. PGS reversed $ 20 2023 and $ 14 Fuel Recovery: PGS recovers the costs it pays for gas supply and interstate transportation for system supply through its PGAC. This clause is designed to recover actual costs incurred by PGS for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, distribution, and sale of natural gas to its customers. These charges may be adjusted monthly based on a cap approved annually by the FPSC. Recovery of Energy Conservation and Pipeline Replacement Programs: The FPSC annually approves a conservation charge that is intended to permit PGS to recover prudently incurred expenditures in developing and implementing cost effective energy conservation programs which are required by Florida law and approved and monitored by the FPSC. PGS also has a Cast Iron/Bare Steel Pipe Replacement clause to recover the cost of accelerating the replacement of cast iron and bare steel distribution lines in the PGS system. In February 2017, the FPSC approved expansion of the Cast Iron/Bare Steel clause to allow recovery of accelerated replacement of certain obsolete plastic pipe. The majority of cast iron and bare steel pipe has been removed from its system, with replacement of obsolete plastic pipe continuing until 2028 under the rider. NMGC NMGC is subject to regulation by the NMPRC. The NMPRC sets rates at a level that allows NMGC to collect total revenues equal to its cost of providing service, plus an appropriate return on invested capital. NMGC’s approved ROE for 2023 and 2022 was 9.375 52 Base Rates: On September 14, 2023, NMGC filed a rate case with the NMPRC for new base rates to become effective Q4 2024. NMGC requested $ 49 operating costs and capital investments in pipeline projects and related infrastructure. The rate case includes a requested ROE of 10.5 Fuel Recovery: NMGC recovers gas supply costs through a PGAC. This clause recovers actual costs for purchased gas, gas storage services, interstate pipeline capacity, and other related items associated with the purchase, transmission, distribution, and sale of natural gas to its customers. On a monthly basis, NMGC can adjust charges based on the next month’s expected cost of gas and any prior month under-recovery or over- recovery. The NMPRC requires that NMGC annually file a reconciliation of the PGAC period costs and recoveries. NMGC must file a PGAC Continuation Filing with the NMPRC every four years to establish that the continued use of the PGAC is reasonable and necessary. NMGC received approval of its PGAC Continuation in December 2020, for the four-year period ending December 2024. Integrity Management Programs (“IMP”) Regulatory Asset: A portion of NMGC’s annual spending on infrastructure is for IMP, legacy systems. These programs are driven both by NMGC integrity management plans and federal and state mandates. In December 2020, NMGC received approval through its rate case to defer costs through an IMP regulatory asset for certain of its IMP capital investments occurring between January 1, 2022 and December 31, 2023 and petitioned recovery of the regulatory asset in its rate case filed on December 13, 2021. On November 30, 2022, the NMPRC issued a Final Order that included approval of recovery of the IMP regulatory asset. Brunswick Pipeline Brunswick Pipeline is a 145 -kilometre pipeline delivering natural gas from the Saint John LNG import terminal near Saint John, New Brunswick to markets in the northeastern United States. Brunswick Pipeline entered into a 25 -year firm service agreement commencing in July 2009 with Repsol Energy North America Canada Partnership. The agreement provides for a predetermined toll increase in the fifth and fifteenth year of the contract. The pipeline is considered a Group II pipeline regulated by the Canada Energy Regulator (“CER”). The CER Gas Transportation Tariff compliance with the requirements of the CER Act and sets forth the terms and conditions of the transportation rendered by Brunswick Pipeline. Other Electric Utilities BLPC BLPC is regulated by the Fair Trading Commission (“FTC”), under the Utilities Regulation (Procedural) Rules 2003. BLPC is regulated under a cost-of-service model, with rates set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on capital invested. BLPC’s approved regulated return on rate base was 10 Licenses: BLPC currently operates pursuant to a single integrated license to generate, transmit and distribute electricity on the island of Barbados until 2028. In 2019, the Government of Barbados passed legislation requiring multiple licenses for the supply of electricity. In 2021, BLPC reached commercial agreement with the Government of Barbados for each of the license types, subject to the passage of implementing legislation. The timing of the final enactment is unknown at this time, but BLPC will work towards the implementation of the licenses once enacted. Base Rates: In 2021, BLPC submitted a general rate review application to the FTC. In September 2022, the FTC granted BLPC interim rate relief, allowing an increase in base rates of approximately $ 1 month. On February 15, 2023, the FTC issued a decision on the significant items: an allowed regulatory ROE of 11.75 55 a directive to update the major components of rate base to September 16, 2022, and a directive to establish regulatory liabilities related to the self-insurance fund of $ 50 recognized on remeasurement of deferred income taxes of $ 5 of $ 16 applied for a stay of the FTC’s decision, which was subsequently granted. On November 20, 2023, the FTC issued their decision dismissing the Motion. Interim rates continue to be in effect through to a date to be determined in a final decision and order. On December 1, 2023, BLPC appealed certain aspects of the FTC’s February 15 and November 20, 2023, decisions to the Supreme Court of Barbados in the High Court of Justice (the “Court”) and requested that they be stayed. On December 11, 2023, the Court granted the stay. that the FTC made errors of law and jurisdiction in their decisions and believes the success of the appeal is probable, and as a result, the adjustments to BLPC’s final rates and rate base, including any adjustments to regulatory assets and liabilities, have not been recorded at this time. Fuel Recovery: BLPC’s fuel costs flow through a fuel pass-through mechanism which provides opportunity to recover all prudently incurred fuel costs from customers in a timely manner. The calculation of the fuel charge is adjusted on a monthly basis and reported to the FTC for approval. Clean Energy Transition Program (“CETP”): On May 31, 2023, the FTC approved BLPC’s application to establish an alternative cost recovery mechanism to recover prudently incurred costs associated with its CETP (the “Decision”). The mechanism is intended to facilitate the timely recovery between rate cases of costs associated with approved renewable energy assets. BLPC will be required to submit an individual application for the recovery of costs of each asset through the cost recovery mechanism, meeting the minimum criteria as set out in the Decision. On October 5, 2023, BLPC applied to the FTC to recover the costs of a battery storage system through the CETP. Fuel Hedging: On October 21, 2021, the FTC approved BLPC’s application to implement a fuel hedging program which will be incorporated into the calculation of the fuel clause adjustment. On November 10, 2021, BLPC requested the FTC review the required 50 /50 cost sharing arrangement between BLPC and customers in relation to the hedging administrative costs, or any gains and losses associated with the hedging program. GBPC GBPC is regulated by the GBPA. The GBPA franchise to produce, transmit and distribute electricity on the island until 2054. Rates are set to recover prudently incurred costs of providing electricity service to customers plus an appropriate return on rate base. GBPC’s approved regulated return on rate base was 8.32 8.23 Base Rates: There is a fuel pass-through mechanism and tariff review policy with new rates submitted every three years. On January 14, 2022, the GBPA issued its decision on GBPC’s application for rate review that was filed with the GBPA on September 23, 2021. The decision, which became effective April 1, 2022, allows for an increase in revenues of $ 3.5 12.84 Fuel Recovery: GBPC’s fuel costs flow through a fuel pass-through mechanism which provides the opportunity to recover all prudently incurred fuel costs from customers in a timely manner. Effective November 1, 2022, GBPC’s fuel pass through charge was increased due to an increase in global oil prices impacting the unhedged fuel cost. In 2023, the fuel pass through charge was adjusted monthly, in-line with actual fuel costs. Storm Restoration Costs – Hurricane Matthew: As part of the recovery of costs incurred as a result of Hurricane Matthew, in 2016, the GBPA approved a fixed per kWh fuel charge and allowed the difference between this and the actual cost of fuel to be applied to the Hurricane Matthew regulatory asset. As part of its decision on GBPC’s application for rate review, issued January 14, 2022, and effective April 1, 2022, the GBPA amortization of the remaining regulatory asset over the three year period ending December 31, 2024. |
Investments Subject to Signific
Investments Subject to Significant Influence and Equity Income | 12 Months Ended |
Dec. 31, 2023 | |
Investments Subject to Significant Influence and Equity Income [Abstract] | |
Investments Subject to Significant Influence and Equity Income | 7. Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2023 2022 2023 2022 2023 LIL (1) $ 747 $ 740 $ 63 $ 58 31.0 NSPML 489 501 46 29 100.0 M&NP 118 128 21 21 12.9 Lucelec (2) 48 49 4 4 19.5 Bear Swamp - - 12 17 50.0 $ 1,402 $ 1,418 $ 146 $ 129 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Emera has significant influence over the operating and financial decisions of these companies through Board representation therefore, records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $ 179 Bear Swamp's credit investment balance of $ 81 95 Consolidated Balance Sheets. Equity investments include a $ 10 investees' assets as at the date of acquisition. The excess is attributable to goodwill. Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2023 2022 Balance Sheets Current assets $ 21 $ 17 PP&E 1,473 1,517 Regulatory assets 272 265 Non-current assets 29 29 Total assets $ 1,795 $ 1,828 Current liabilities $ 48 $ 48 Long-term debt (1) 1,109 1,149 Non-current liabilities 149 130 Equity 489 501 Total liabilities and equity $ 1,795 $ 1,828 (1) The project debt has been guaranteed by the Government of Canada. |
Other Income, Net
Other Income, Net | 12 Months Ended |
Dec. 31, 2023 | |
Other Income, Net [Abstract] | |
Other Income, Net | 8. For the Year ended December 31 millions of dollars 2023 2022 Interest income $ 43 $ 25 AFUDC 38 52 Pension non-current service cost recovery 35 24 FX gains (losses) 20 (26) TECO Guatemala Holdings award (1) - 63 Other 22 7 $ 158 $ 145 (1) On December 15, 2022, a payment of $ 63 second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute an investment in TGH, a wholly-owned subsidiary of TECO Energy. |
Interest Expense, Net
Interest Expense, Net | 12 Months Ended |
Dec. 31, 2023 | |
Interest Expense, Net [Abstract] | |
Interest Expense, Net | 9. Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2023 2022 Interest on debt $ 954 $ 727 Allowance for borrowed funds used during construction (16) (21) Other (13) 3 $ 925 $ 709 |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Income Taxes | 10. The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2023 2022 Income before provision for income taxes $ 1,173 $ 1,194 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 340 346 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (72) (70) Tax credits (53) (18) Foreign tax rate variance (36) (44) Amortization of deferred income tax regulatory liabilities (33) (33) Tax effect (15) (10) GBPC impairment charge - 21 Other (3) (7) Income tax expense $ 128 $ 185 Effective income tax rate 11% 15% On August 16, 2022, the United States Inflation Reduction Act (“IRA”) was signed into legislation. The IRA includes numerous tax incentives for clean energy, such as the extension and modification of existing investment and production tax credits for projects placed in service through 2024 and introduces new technology-neutral clean energy related tax credits beginning in 2025. As of December 31, 2023, the Company has recorded a $ 30 9 Sheets in recognition of its obligation to pass the incremental tax benefits realized to customers. The following table reflects the composition of taxes on income from continuing operations presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Current income taxes $ 26 $ 25 5 8 Deferred income taxes 93 122 128 252 Investment tax credits (29) (7) Operating loss carryforwards (93) (94) (2) (121) Income tax expense $ 128 $ 185 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Canada $ 171 $ 173 United States 964 1,063 Other 38 (42) Income before provision for income taxes $ 1,173 $ 1,194 The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2023 2022 Deferred income tax assets: Tax loss carryforwards $ 1,195 $ 1,207 Tax credit carryforwards 454 415 Derivative instruments 205 45 Regulatory liabilities 175 264 Other 372 341 Total deferred income tax assets before valuation allowance 2,401 2,272 Valuation allowance (363) (312) Total deferred income tax assets after valuation allowance $ 2,038 $ 1,960 Deferred income tax (liabilities): PP&E $ (3,223) $ (2,981) Derivative instruments (235) (125) Investments subject to significant influence (216) (181) Regulatory assets (196) (310) Other (312) (322) Total deferred income tax liabilities $ (4,182) $ (3,919) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 208 $ 237 Long-term deferred income tax liabilities (2,352) (2,196) Net deferred income tax liabilities $ (2,144) $ (1,959) Considering all evidence regarding the utilization of the Company’s deferred income tax assets, it has been determined that Emera is more likely than not to realize all recorded deferred income tax assets, except for certain loss carryforwards and unrealized capital losses on long-term debt and investments. A valuation allowance of $ 363 312 related to the loss carryforwards, long-term debt and investments. The Company intends to indefinitely reinvest earnings from certain foreign operations. Accordingly, as at December 31, 2023, $ 4.7 3.8 deferred taxes might otherwise be required, have not been recognized. It is impractical to estimate the amount of income and withholding tax that might be payable if a reversal of temporary differences occurred. Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2023 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,914 $ (1,164) $ 1,750 2026 - 2043 73 (73) - Indefinite United States $ 1,360 $ (1) $ 1,359 2036 - Indefinite 1,003 (1) 1,002 2026 - Indefinite 454 (3) 451 2025 - 2043 Other $ 81 $ (28) $ 53 2024 - 2030 The following table provides details of the change in unrecognized tax benefits for the years ended December 31 as follows: millions of dollars 2023 2022 Balance, January 1 $ 33 $ 28 Increases due to tax positions related to current year 5 5 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (2) (2) Balance, December 31 $ 37 $ 33 Unrecognized tax benefits relate to the timing of certain tax deductions at NSPI and research and development tax credits primarily at TEC. The total amount of unrecognized tax benefits as at December 31, 2023 was $ 37 33 total amount of accrued interest with respect to unrecognized tax benefits was $ 9 7 million) with $ 2 1 million). No next 12 months as a result of resolving Canada Revenue Agency (“CRA”) and Internal Revenue Service audits. A reasonable estimate of any change cannot be made at this time. During 2022, the CRA issued notices of reassessment to NSPI for the 2013 through 2016 taxation years. NSPI and the CRA are currently in a dispute with respect to the timing of certain tax deductions for its 2006 through 2010 and 2013 through 2016 taxation years. The ultimate permissibility of the tax deductions is not in dispute; rather, it is the timing of those deductions. The cumulative net amount in dispute to date is $ 126 126 55 the amount in dispute, as required by CRA. On November 29, 2019, NSPI filed a Notice of Appeal with the Tax Court of Canada with respect to its dispute of the 2006 through 2010 taxation years. Should NSPI be successful in defending its position, all payments including applicable interest will be refunded. If NSPI is unsuccessful in defending any portion of its position, the resulting taxes and applicable interest will be deducted from amounts previously paid, with the difference, if any, either owed to, or refunded from, the CRA. The related tax deductions will be available in subsequent years. Should NSPI be similarly reassessed by the CRA for years not currently in dispute, further payments will be required; however, the ultimate permissibility of these deductions would be similarly not in dispute. NSPI and its advisors believe that NSPI has reported its tax position appropriately. NSPI continues to assess its options to resolving the dispute; however, the outcome of the Notice of Appeal process is not determinable at this time. Emera files a Canadian federal income tax return, which includes its Nova Scotia provincial income tax. Emera’s subsidiaries file Canadian, US, Barbados, and St. Lucia income tax returns. As at December 31, 2023, the Company’s tax years still open to examination by taxing authorities include 2005 and subsequent years. |
Common Stock
Common Stock | 12 Months Ended |
Dec. 31, 2023 | |
Common Stock [Abstract] | |
Common Stock | 11. Authorized : 2023 2022 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 269.95 $ 7,762 261.07 $ 7,242 Issuance of common stock under ATM program (1)(2) 8.29 397 4.07 248 Issued under the DRIP, 5.26 272 4.21 238 Senior management stock options exercised and Employee Share Purchase Plan 0.62 31 0.60 34 Balance, December 31 284.12 $ 8,462 269.95 $ 7,762 (1) For the year ended December 31, 2022, a total of 4,072,469 average price of $ 61.31 250 248 (2) For the year ended December 31, 2023, a total of 8,287,037 average price of $ 48.27 400 397 As at December 31, 2023, the following common shares were reserved for issuance: 6 6 million) under the senior management stock option plan, 2 2.7 common share purchase plan and 18 10 The issuance of common shares under the common share compensation arrangements does not allow the plans to exceed 10 Emera was in compliance with this requirement. ATM Equity Program On October 3, 2023, Emera filed a short form base shelf prospectus, primarily in support of the renewal of its ATM Program in Q4 2023 that will allow the Company to issue up to $ 600 from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price. This ATM Program is expected to remain in effect until November 4, 2025. |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 12. Basic earnings per share is determined by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding during the period, adjusted for the exercise and/or conversion of all potentially dilutive securities. Such dilutive items include Company contributions to the senior management stock option plan, convertible debentures and shares issued under the DRIP. The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2023 2022 Numerator Net income attributable to common shareholders $ 977.7 $ 945.1 Diluted numerator 977.7 945.1 Denominator Weighted average shares of common stock outstanding – basic 273.6 265.5 Stock-based compensation 0.2 0.4 Weighted average shares of common stock outstanding – diluted 273.8 265.9 Earnings per common share Basic $ 3.57 $ 3.56 Diluted $ 3.57 $ 3.55 |
Accumulated Other Comprehensive
Accumulated Other Comprehensive Income | 12 Months Ended |
Dec. 31, 2023 | |
Accumulated Other Comprehensive Income [Abstract] | |
Accumulated Other Comprehensive Income | 13. The components of AOCI are as follows: millions of dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges Losses on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 Other comprehensive (loss) income before reclassifications (270) 38 - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period other comprehensive (loss) income (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 Other comprehensive income (loss) before reclassifications 629 (97) - (1) - 531 Amounts reclassified from AOCI - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2023 2022 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ - $ 10 Other income, net 2 - Pension and post-retirement benefits (40) 15 Total before tax (38) 25 Income tax expense (1) (1) Total net of tax $ (39) $ 24 Total reclassifications out of AOCI, net of tax, for the period $ (41) $ 22 |
Inventory
Inventory | 12 Months Ended |
Dec. 31, 2023 | |
Inventory [Abstract] | |
Inventory | 14. As at December 31 December 31 millions of dollars 2023 2022 Fuel $ 382 $ 404 Materials 408 365 Total $ 790 $ 769 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments | |
Derivative Instruments | 15. Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2023 2022 2023 2022 Regulatory deferral: $ 16 $ 186 $ 76 $ 42 3 18 3 1 - 52 - - 19 256 79 43 HFT derivatives: 29 89 36 77 319 340 531 1,224 348 429 567 1,301 Other derivatives: 4 - - 5 18 5 7 23 22 5 7 28 Total gross current derivatives 389 690 653 1,372 Impact of master netting agreements: (3) (18) (3) (18) (146) (276) (146) (276) Total impact of master netting agreements (149) (294) (149) (294) Total derivatives $ 240 $ 396 $ 504 $ 1,078 Current (1) 174 296 386 888 Long-term (1) 66 100 118 190 Total derivatives $ 240 $ 396 $ 504 $ 1,078 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying Cash Flow Hedges On May 26, 2021, a treasury lock was settled for a gain of $ 19 interest expense over 10 years The amounts related to cash flow hedges recorded in AOCI consisted of the following: For the Year ended December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Realized gain in interest expense, net $ 2 $ 2 Total gains in net income $ 2 $ 2 As at December 31 December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Total unrealized gain in AOCI – effective portion, net of tax $ 14 $ 16 The Company expects $ 2 within the next 12 months. Regulatory Deferral The Company has recorded the following changes with respect to derivatives receiving regulatory deferral: Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2023 2022 Unrealized gain (loss) in regulatory assets $ - $ (109) $ (3) $ - $ (69) $ 1 Unrealized gain (loss) in regulatory liabilities (3) (73) - 28 343 16 Realized (gain) loss in regulatory assets - (5) - - 48 - Realized (gain) loss in regulatory liabilities - 2 - - (41) - Realized (gain) loss in inventory (1) - 4 (10) - (121) 1 Realized (gain) in regulated fuel for generation and purchased power (2) (49) (9) (4) (64) (146) - Other - (14) - - - - Total change in derivative instruments $ (52) $ (204) $ (17) $ (36) $ 14 $ 18 (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. As at December 31, 2023, the Company had the following notional volumes designated for regulatory deferral that are expected to settle as outlined below: millions 2024 2025-2026 Physical natural gas purchases: Natural gas (MMBtu) 7 6 Commodity swaps and forwards purchases: Natural gas (MMBtu) 16 10 Power (MWh) 1 1 Coal (metric tonnes) 1 - FX swaps and forwards: FX contracts (millions of USD) $ 241 $ 70 Weighted average rate 1.3155 1.3197 % of USD requirements 63% 17% HFT Derivatives The Company has recognized the following realized and unrealized gains (losses) with respect to HFT derivatives: For the Year ended December 31 millions of dollars 2023 2022 Power swaps and physical contracts in non-regulated operating revenues $ (6) $ 17 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 1,043 47 Total gains in net income $ 1,037 $ 64 As at December 31, 2023, the Company had the following notional volumes of outstanding HFT derivatives that are expected to settle as outlined below: 2028 and millions 2024 2025 2026 2027 thereafter Natural gas purchases (Mmbtu) 296 80 50 38 30 Natural gas sales (Mmbtu) 338 86 16 6 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - Other Derivatives As at December 31, 2023, the Company had equity derivatives in place to manage the cash flow risk associated with forecasted future cash settlements of deferred compensation obligations and FX forwards in place to manage cash flow risk associated with forecasted USD cash inflows. The equity derivatives hedge the return on 2.9 combined notional amount of $508 million USD and expire in 2023, 2024 and 2025. For the Year ended December 31 millions of dollars 2023 2022 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ 4 $ - $ (5) Unrealized gain (loss) in other income, net 28 - (18) - Realized loss in OM&G - (13) - (17) Realized loss in other income, net (11) - (6) - Total gains (losses) in net income $ 17 $ (9) $ (24) $ (22) Credit Risk The Company is exposed to credit risk with respect to amounts receivable from customers, energy marketing collateral deposits and derivative assets. Credit risk is the potential loss from a counterparty’s non-performance under an agreement. The Company manages credit risk with policies and procedures for counterparty analysis, exposure measurement, and exposure monitoring and mitigation. Credit assessments are conducted on all new customers and counterparties, and deposits or collateral are requested on any high-risk accounts. The Company assesses the potential for credit losses on a regular basis and, where appropriate, maintains provisions. With respect to counterparties, the Company has implemented procedures to monitor the creditworthiness and credit exposure of counterparties and to consider default probability in valuing the counterparty positions. The Company monitors counterparties’ credit standing, including those that are experiencing financial problems, have significant swings in default probability rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are adjusted based on the Company’s current default probability. Net asset positions are adjusted based on the counterparty’s current default probability. The Company assesses credit risk internally for counterparties that are not rated. As at December 31, 2023, the maximum exposure the Company had to credit risk was $ 1.2 – $ 1.9 derivatives. It is possible that volatility in commodity prices could cause the Company to have material credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations under one or more agreements, the Company could suffer a material financial loss. The Company transacts with counterparties as part of its risk management strategy for managing commodity price, FX and interest rate risk. Counterparties that exceed established credit limits can provide a cash deposit or letter of credit to the Company for the value in excess of the credit limit where contractually required. The total cash deposits/collateral on hand as at December 31, 2023 was $ 310 386 mitigated the Company’s maximum credit risk exposure. The Company uses the cash as payment for the amount receivable or returns the deposit/collateral to the customer/counterparty where it is no longer required by the Company. The Company enters into commodity master arrangements with its counterparties to manage certain risks, including credit risk to these counterparties. The Company generally enters into International Swaps and Derivatives Association agreements, North American Energy Standards Board agreements and, or Edison Electric Institute agreements. The Company believes entering into such agreements offers protection by creating contractual rights relating to creditworthiness, collateral, non-performance and default. As at December 31, 2023, the Company had $ 142 131 considered to be past due, which have been outstanding for an average 64 financial assets was $ 127 114 allowance for credit losses. These assets primarily relate to accounts receivable from electric and gas revenue. Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2023 December 31, 2022 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 476 31% $ 455 19% Commercial 194 13% 192 8% Industrial 84 5% 121 5% Other 103 7% 122 5% Cash collateral 94 6% - 0% 951 62% 890 37% Trading group: Credit rating of A- or above 47 3% 125 5% Credit rating of BBB- to BBB+ 33 2% 75 3% Not rated 108 7% 307 13% 188 12% 507 21% Other accounts receivable 151 10% 585 25% 1,290 84% 1,982 83% Derivative Instruments (current and long-term) Credit rating of A- or above 138 9% 202 9% Credit rating of BBB- to BBB+ 7 1% 8 0% Not rated 95 6% 186 8% 240 16% 396 17% $ 1,530 100% $ 2,378 100% Cash Collateral The Company’s cash collateral positions consisted of the following: As at December 31 December 31 millions of dollars 2023 2022 Cash collateral provided to others $ 101 $ 224 Cash collateral received from others $ 22 $ 112 Collateral is posted in the normal course of business based on the Company’s creditworthiness, including its senior unsecured credit rating as determined by certain major credit rating agencies. Certain derivatives contain financial assurance provisions that require collateral to be posted if a material adverse credit-related event occurs. If a material adverse event resulted in the senior unsecured debt falling below investment grade, the counterparties to such derivatives could request ongoing full collateralization. As at December 31, 2023, the total FV of derivatives in a liability position was $ 504 2022 – 1,078 value of the net liability position could be required to be posted as collateral for these derivatives. |
FV Measurements
FV Measurements | 12 Months Ended |
Dec. 31, 2023 | |
FV Measurements [Abstract] | |
Fair Value Measurements | 16. The Company is required to determine the FV of all derivatives except those which qualify for the NPNS exemption (see note 1) and uses a market approach to do so. The three levels of the FV hierarchy are defined as follows: Level 1 - Where possible, the Company bases the fair valuation of its financial assets and liabilities on quoted prices in active markets (“quoted prices”) for identical assets and liabilities. Level 2 - Where quoted prices for identical assets and liabilities are not available, the valuation of certain contracts must be based on quoted prices for similar assets and liabilities with an adjustment related to location differences. Also, certain derivatives are valued using quotes from over-the-counter clearing houses. Level 3 - Where the information required for a Level 1 or Level 2 valuation is not available, derivatives must be valued using unobservable or internally-developed inputs. The primary reasons for a Level 3 classification are as follows: ● seasonal or monthly shaping and locational basis differentials. ● accordingly, assumptions were made to extrapolate prices from the last quoted period through the end of the transaction term. ● utilized in the valuations. Derivative assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the FV measurement. The following tables set out the classification of the methodology used by the Company to FV its derivatives: As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264) As at December 31, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2023 $ 52 $ 4 $ 34 $ 90 Realized gains (losses) included in fuel for generation and purchased power (49) - - (49) Unrealized gains (losses) included in regulatory assets and liabilities (3) - - (3) Total realized and unrealized gains (losses) included in non-regulated operating revenues - (4) - (4) Balance, December 31, 2023 $ - $ - $ 34 $ 34 The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2023 $ 1 $ 825 $ 826 Total realized and unrealized gains included in non- regulated operating revenues (1) (460) (461) Balance, December 31, 2023 $ - $ 365 $ 365 Significant unobservable inputs used in the FV measurement of Emera’s natural gas and power derivatives include third-party sourced pricing for instruments based on illiquid markets. Significant increases (decreases) in any of these inputs in isolation would result in a significantly lower (higher) FV measurement. Other unobservable inputs used include internally developed correlation factors and basis differentials; own credit risk; and discount rates. Internally developed correlations and basis differentials are reviewed on a quarterly basis based on statistical analysis of the spot markets in the various illiquid term markets. Discount rates may include a risk premium for those long-term forward contracts with illiquid future price points to incorporate the inherent uncertainty of these points. Any risk premiums for long-term contracts are evaluated by observing similar industry practices and in discussion with industry peers. The Company uses a modelled pricing valuation technique for determining the FV of Level 3 derivative instruments. The following table outlines quantitative information about the significant unobservable inputs used in the FV measurements categorized within Level 3 of the FV hierarchy: Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 As at December 31, 2022 Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (1) Unobservable inputs were weighted by the relative FV of the instruments. Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621 December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 The Company has designated $ 1.2 currency exposure of its ne t investment are contingently convertible into preferred shares in the event of bankruptcy or other related events. A redemption option on or after June 15, 2026 is available and at the control of the Company. The Hybrid Notes are classified as Level 2 financial assets. As at December 31, 2023, the FV of the Hybrid Notes was $ 1.2 1.1 38 AOCI for the year ended December 31, 2023 (2022 – $ 97 |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2023 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | 17. In the ordinary course of business, Emera provides energy and other services and enters into transactions with its subsidiaries, associates and other related companies on terms similar to those offered to non-related parties. Intercompany balances and intercompany transactions have been eliminated on consolidation, except for the net profit on certain transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. All material amounts are under normal interest and credit terms. Significant transactions between Emera and its associated companies are as follows: ● Consolidated Statements of Income. NSPI’s expense is reported in Regulated fuel for generation and purchased power, totalling $ 163 157 NSPML is accounted for as an equity investment, and therefore corresponding earnings related to this revenue are reflected in Income from equity investments. Natural gas transportation capacity purchases from M&NP are reported in the Consolidated Statements of Income. Purchases from M&NP reported net in Operating revenues, Non-regulated, totalled $ 14 – $ 9 There were no significant receivables or payables between Emera and its associated companies reported on Emera’s Consolidated Balance Sheets as at December 31, 2023 and at December 31, 2022. |
Receivables and Other Current A
Receivables and Other Current Assets | 12 Months Ended |
Dec. 31, 2023 | |
Receivables and Other Current Assets [Abstract] | |
Receivables and Other Current Assets | 18. As at December 31 December 31 millions of dollars 2023 2022 Customer accounts receivable – billed $ 805 $ 1,096 Capitalized transportation capacity (1) 358 781 Customer accounts receivable – unbilled 363 424 Prepaid expenses 105 82 Income tax receivable 10 9 Allowance for credit losses (15) (17) NMGC gas hedge settlement receivable 162 Other 191 360 Total receivables and other current assets $ 1,817 $ 2,897 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract. (2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, to note 6. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases, Lessee | 19. Lessee The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised. As at December 31 December 31 millions of dollars Classification 2023 2022 Right-of-use asset Other long-term assets $ 54 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 55 59 Total lease liabilities $ 58 $ 62 The Company recorded lease expense of $ 127 $ 138 119 131 facility finance leases, recorded in “Regulated fuel for generation and purchased power” in the Consolidated Statements of Income. Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments $ 6 $ 5 $ 3 $ 3 $ 3 $ 111 $ 131 Less imputed interest (73) Total $ 58 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2023 2022 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.93% 3.98% Lessor The Company’s net investment in direct finance and sales-type leases primarily relates to Brunswick Pipeline, Seacoast, compressed natural gas (“CNG”) stations, a renewable natural gas (“RNG”) facility and heat pumps. The Company manages its risk associated with the residual value of the Brunswick Pipeline lease through proper routine maintenance of the asset. Customers have the option to purchase CNG station assets by paying a make-whole payment at the date of the purchase based on a targeted internal rate of return or may take possession of the CNG station asset at the end of the lease term for no cost. Customers have the option to purchase heat pumps at the end of the lease term for a nominal fee. Commencing in October 2023, the Company leased a RNG facility to a biogas producer that is classified as a sales-type lease. The term of the facility lease is 15 years , with a nominal value purchase at the end of the term and a net investment of approximately $ 35 Commencing in January 2022, the Company leased Seacoast pipeline, a 21-mile, 30-inch lateral that is classified as a sales-type lease. The term of the pipeline lateral lease is 34 $ 100 16 renewal options have not been included as part of the pipeline lateral lease term as it is not reasonably certain that they will be exercised. Direct finance and sales-type lease unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease and is recorded as “Operating revenues – regulated gas” and “Other income, net” on the Consolidated Statements of Income. The total net investment in direct finance and sales-type leases consist of the following: As at December 31 December 31 millions of dollars 2023 2022 Total minimum lease payment to be received $ 1,360 $ 1,393 Less: amounts representing estimated executory costs (190) (205) Minimum lease payments receivable $ 1,170 $ 1,188 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) - Less: unearned finance lease income (693) (733) Net investment in direct finance and sales-type leases $ 658 $ 638 Principal due within one year (included in "Receivables and other current assets") 37 34 Net Investment in direct finance and sales type leases - long-term $ 621 $ 604 As at December 31, 2023, future minimum lease payments to be received for each of the next five years and in aggregate thereafter were as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments to be received $ 97 $ 99 $ 98 $ 97 $ 96 $ 873 $ 1,360 Less: executory costs (190) Total $ 1,170 |
Property, Plant and Equipment
Property, Plant and Equipment | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Property, Plant and Equipment | 20. PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2023 2022 Generation 3 131 $ 13,500 $ 13,083 Transmission 10 80 2,835 2,731 Distribution 4 80 7,417 6,978 Gas transmission and distribution 6 92 5,536 5,061 General plant and other 2 71 2,985 2,723 Total cost 32,273 30,576 Less: Accumulated depreciation (1) (9,994) (9,574) 22,279 21,002 Construction work in progress (1) 2,097 1,994 Net book value $ 24,376 $ 22,996 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 2 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2023 | |
Employee Benefit Plans [Abstract] | |
Employee Benefit Plans | 21. Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island. Emera’s net periodic benefit cost included the following: Benefit Obligation and Plan Assets: The changes in benefit obligation and plan assets, and the funded status for all plans were as follows: For the Year ended December 31 millions of dollars 2023 2022 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,158 $ 243 $ 2,624 $ 318 Service cost 30 3 41 4 Plan participant contributions 6 6 6 6 Interest cost 111 13 80 9 Plan amendments - (14) - - Benefits paid (147) (29) (174) (31) Actuarial losses (gains) 146 10 (480) (79) Settlements and curtailments (8) - (6) - FX translation adjustment (23) (5) 67 16 Balance, December 31 $ 2,273 $ 227 $ 2,158 $ 243 Change in plan assets Balance, January 1 $ 2,163 $ 46 $ 2,702 $ 51 Employer contributions 42 23 45 24 Plan participant contributions 6 6 6 6 Benefits paid (147) (29) (174) (31) Actual return on assets, net of expenses 262 3 (489) (7) Settlements and curtailments (8) - (6) - FX translation adjustment (20) (1) 79 3 Balance, December 31 $ 2,298 $ 48 $ 2,163 $ 46 Funded status, end of year $ 25 $ (179) $ 5 $ (197) The actuarial losses recognized in the period are primarily due to changes in the discount rate, higher than expected indexation, and compensation-related assumption changes. Plans with PBO/APBO in Excess of Plan Assets: The aggregate financial position for all pension plans where the PBO or APBO (for post-retirement benefit plans) exceeded the plan assets for the years ended December 31 was as follows: millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 120 $ 205 $ 1,006 $ 221 FV of plan assets 37 - 914 - Funded status $ (83) $ (205) $ (92) $ (221) Plans with Accumulated Benefit Obligation (“ABO”) in Excess of Plan Assets: The ABO for the DB pension plans was $ 2,172 2,080 The aggregate financial position for those plans with an ABO in excess of the plan assets for the years ended December 31 was as follows: millions of dollars 2023 2022 Defined benefit pension plans Defined benefit pension plans ABO $ 114 $ 111 FV of plan assets 37 33 Funded status $ (77) $ (78) Balance Sheet: The amounts recognized in the Consolidated Balance Sheets consisted of the following: As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (5) $ (18) $ (13) $ (20) Long-term liabilities (78) (187) (80) (201) Other long-term assets 108 26 98 24 AOCI, net of tax and regulatory assets 385 20 358 22 Less: Deferred income tax (expense) recovery in AOCI (8) (1) (7) (1) Net amount recognized $ 402 $ (160) $ 356 $ (176) Amounts Recognized in AOCI and Regulatory Assets: Unamortized gains and losses and past service costs arising on post-retirement benefits are recorded in AOCI or regulatory assets. The following table summarizes the change in AOCI and regulatory assets: Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of dollars Defined Benefit Pension Plans Balance, January 1, 2023 $ 336 $ 15 $ - Amortized in current period (6) (3) - Current year additions 1 41 - Change in FX rate (7) - - Balance, December 31, 2023 $ 324 $ 53 $ - Non-pension benefits plans Balance, January 1, 2023 $ 31 $ (10) $ - Amortized in current period 2 3 - Current year reductions (3) (1) (3) Change in FX rate (1) - 1 Balance, December 31, 2023 $ 29 $ (8) $ (2) As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 53 (8) $ 15 $ (10) Past service gains - (2) - - Deferred income tax expense 8 1 7 1 AOCI, net of tax 61 (9) 22 (9) Regulatory assets 324 29 336 31 AOCI, net of tax and regulatory assets $ 385 $ 20 $ 358 $ 22 Benefit Cost Components: Emera's net periodic benefit cost included the following: As at Year ended December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 30 $ 3 $ 41 $ 4 Interest cost 111 13 80 9 Expected return on plan assets (161) (2) (144) - Current year amortization of: 1 (3) 8 - 6 (2) 21 2 Settlement, curtailments 2 - 2 - Total $ (11) $ 9 $ 8 $ 15 The expected return on plan assets is determined based on the market-related value of plan assets of $ 2,577 2,482 during the year. The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. Pension Plan Asset Allocations: Emera’s investment policy includes discussion regarding the investment philosophy, the level of risk which the Company is prepared to accept with respect to the investment of the Pension Funds, and the basis for measuring the performance of the assets. Central to the policy is the target asset allocation by major asset categories. The objective of the target asset allocation is to diversify risk and to achieve asset returns that meet or exceed the plan’s actuarial assumptions. The diversification of assets reduces the inherent risk in financial markets by requiring that assets be spread out amongst various asset classes. Within each asset class, a further diversification is undertaken through the investment in a broad range of investment and non-investment grade securities. Emera’s target asset allocation is as follows: Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 7% to 17% 35% to 59% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68% Pension Plan assets are overseen by the respective Management Pension Committees in the sponsoring companies. All pension investments are in accordance with policies approved by the respective Board of Directors of each sponsoring company. The following tables set out the classification of the methodology used by the Company to FV its investments: millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2023 Cash and cash equivalents $ - $ 40 $ - $ 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % (1) Net asset value ("NAV") investments are open-ended or pooled funds. NAV’s are calculated (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour subscription and redemption activity regularly. Refer to note 16 for more information on the FV hierarchy and inputs used to measure FV. Post-Retirement Benefit Plans: There are no assets set aside to pay for most of the Company’s post-retirement benefit plans. As is common practice, post-retirement health benefits are paid from general accounts as required. The primary exception to this is the NMGC Retiree Medical Plan, which is fully funded. Investments in Emera: As at December 31, 2023 and 2022, assets related to the pension funds and post-retirement benefit plans did not hold any material investments in Emera or its subsidiaries securities. However, as a significant portion of assets for the benefit plan are held in pooled assets, there may be indirect investments in these securities. Cash Flows: The following table shows expected cash flows for DB pension and other post-retirement benefit plans: millions of dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2024 $ 34 $ 19 Expected benefit payments 2024 172 21 2025 163 21 2026 166 21 2027 171 21 2028 173 20 2029 – 2033 890 95 Assumptions: The following table shows the assumptions that have been used in accounting for DB pension and other post-retirement benefit plans: 2023 2022 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Benefit cost for year ended December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Expected long-term return on plan assets 6.56 % 2.16 % 6.07 % 1.32 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Actual assumptions used differ by plan. The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. The discount rate is based on high-quality long-term corporate bonds, with maturities matching the estimated cash flows from the pension plan. Defined Contribution Plan: Emera also provides a DC pension plan for certain employees. The Company’s contribution for the year ended December 31, 2023 was $ 45 41 |
Goodwill
Goodwill | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Goodwill | 22. The change in goodwill for the year ended December 31 was due to the following: millions of dollars 2023 2022 Balance, January 1 $ 6,012 $ 5,696 Change in FX rate (141) 389 GBPC impairment charge - (73) Balance, December 31 $ 5,871 $ 6,012 Goodwill is subject to an annual assessment for impairment at the reporting unit level. The goodwill on Emera’s Consolidated Balance Sheets at December 31, 2023, primarily related to TECO Energy (reporting units with goodwill are TEC, PGS, and NMGC). In 2023, Emera performed qualitative impairment assessments for NMGC and PGS, concluding that the FV of the reporting units exceeded their respective carrying amounts, and as such, no quantitative assessments were performed and no passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income approach and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result no charges were recognized. In 2022, the Company elected to bypass a qualitative assessment and performed a quantitative impairment assessment for GBPC, using the income approach. It was determined that the FV did not exceed its carrying amount, including goodwill. As a result of this assessment, a goodwill impairment charge of $ 73 31, 2022. This non-cash charge is included in “GBPC impairment charge” on the Consolidated Statements of Income. |
Short-Term Debt
Short-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
Short-Term Debt [Abstract] | |
Short-Term Debt | 23. Emera’s short-term borrowings consist of commercial paper issuances, advances on revolving and non- revolving credit facilities and short-term notes. Short-term debt and the related weighted-average interest rates as at December 31 consisted of the following: millions of dollars 2023 Weighted average interest rate 2022 Weighted average interest rate TEC Advances on revolving credit facilities $ 277 5.68 % $ 1,380 5.00 % Emera Non-revolving term facilities 796 6.07 % 796 5.19 % Bank indebtedness 9 - % - - % TECO Finance Advances on revolving credit and term facilities 245 6.54 % 481 5.47 % PGS Advances on revolving credit facilities 73 6.36 % - - % NMGC Advances on revolving credit facilities 25 6.46 % 59 5.15 % GBPC Advances on revolving credit facilities 8 5.54 % 10 5.25 % Short-term debt $ 1,433 $ 2,726 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 TEC - Unsecured committed revolving credit facility 2026 $ 401 $ 1,084 TECO Energy/TECO Finance - revolving credit facility 2026 - 542 TECO Finance - Unsecured committed revolving credit facility 2026 529 - Emera - Unsecured non-revolving term facility 2024 400 400 Emera - Unsecured non-revolving term facility 2024 400 400 PGS - Unsecured revolving credit facility 2028 331 - TEC - Unsecured revolving facility 2024 265 542 TEC - Unsecured revolving facility 2024 265 - NMGC - Unsecured revolving credit facility 2026 165 169 Other - Unsecured committed revolving credit facilities Various 17 18 Total $ 2,773 $ 3,155 Less: Advances under revolving credit and term facilities 1,433 2,731 Letters of credit issued within the credit facilities 3 4 Total advances under available facilities 1,436 2,735 Available capacity under existing agreements $ 1,337 $ 420 The weighted average interest rate on outstanding short-term debt at December 31, 2023 was 5.95 cent (2022 – 5.01 Recent Significant Financing Activity by Segment Florida Electric Utilities On November 24, 2023, TEC repaid its $ 400 on December 13, 2023 . On April 3, 2023, TEC entered into a 364 -day, $ 200 which matures on April 1, 2024 . The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term secured overnight financing rate (“SOFR”), Wells Fargo’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. On March 1, 2023, TEC entered into a 364 -day, $ 200 facility which matures on February 28, 2024 . The credit facility contains customary representations and warranties, events of default and financial and other covenants, and bears interest at a variable interest rate, based on either the term SOFR, the Bank of Nova Scotia’s prime rate, the federal funds rate or the one-month SOFR, plus a margin. Gas Utilities and Infrastructure On December 1, 2023, PGS entered into a $ 250 with a group of banks, maturing on December 1, 2028 . PGS has the ability to request the lenders to increase their commitments under the credit facility by up to $ 100 agreement from participating lenders. The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. Other On December 16, 2023, Emera amended its $ 400 maturity date from December 16, 2023 December 16, 2024 . There were no other changes in commercial terms from the prior agreement. On June 30, 2023, Emera amended its $ 400 maturity date from August 2, 2023 August 2, 2024 . There were no other changes in commercial terms from the prior agreement. |
Other Current Liabilities
Other Current Liabilities | 12 Months Ended |
Dec. 31, 2023 | |
Other Current Liabilities | |
Other Current Liabilities | 24. As at December 31 December 31 millions of dollars 2023 2022 Accrued charges $ 172 $ 174 Nova Scotia Cap-and-Trade Program provision (note 6) - 172 Accrued interest on long-term debt 107 97 Pension and post-retirement liabilities (note 21) 23 33 Sales and other taxes payable 11 14 Income tax payable 2 9 Other 112 80 $ 427 $ 579 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
Long-term Debt [Abstract] | |
Long-term Debt | 25. Bonds, notes and debentures are at fixed interest rates and are unsecured unless noted below. Included are certain bankers’ acceptances and commercial paper where the Company has the intention and the unencumbered ability to refinance the obligations for a period greater than one year. Long-term debt as at December 31 consisted of the following: Weighted average interest rate (1) millions of dollars 2023 2022 Maturity 2023 2022 Emera Bankers acceptances, SOFR loans Variable Variable 2027 $ 465 $ 403 Unsecured fixed rate notes 4.84% 2.90% 2030 500 500 Fixed to floating subordinated notes (2) 6.75% 6.75% 2076 1,587 1,625 $ 2,552 $ 2,528 Emera Finance Unsecured senior notes 3.65% 3.65% 2024 - 2046 $ 3,637 $ 3,725 TEC (3) Fixed rate notes and bonds 4.61% 4.15% 2024 - 2051 $ 5,654 $ 4,341 PGS Fixed rate notes and bonds 5.63% 3.78% 2028 - 2053 $ 1,223 $ 772 NMGC Fixed rate notes and bonds 3.78% 3.11% 2026 - 2051 $ 642 $ 521 Non-revolving term facility, floating rate Variable Variable 2024 30 108 $ 672 $ 629 NMGI Fixed rate notes and bonds 3.64% 3.64% 2024 $ 198 $ 203 NSPI Discount Notes (4) Variable Variable 2024 - 2027 $ 721 $ 881 Medium term fixed rate notes 5.13% 5.14% 2025 - 2097 3,165 2,665 $ 3,886 $ 3,546 EBP Senior secured credit facility Variable Variable 2026 $ 246 $ 249 ECI Secured senior notes Variable Variable 2027 $ 75 $ 86 Amortizing fixed rate notes 4.00% 3.97% 2026 79 100 Non-revolving term facility, floating rate Variable Variable 2025 29 30 Non-revolving term facility, fixed rate 2.15% 2.05% 2025 - 2027 155 91 Secured fixed rate senior notes (5) 3.09% 3.06% 2024 - 2029 84 142 $ 422 $ 449 Adjustments Fair market value adjustment - TECO Energy acquisition $ - $ 2 Debt issuance costs (125) (126) Amount due within one year (676) (574) $ (801) $ (698) Long-Term Debt $ 17,689 $ 15,744 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2023, the Company recognized $ 109 110 subordinated notes. (3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently bonds outstanding under TEC’s first mortgage bond indenture. (4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’ acceptances for a period of greater than one year. (5) Notes are issued and payable in either USD or BBD. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 TEC - Unsecured committed revolving credit facility December 2026 657 - NSPI - revolving credit facility (1) December 2027 800 800 NSPI - non-revolving credit facility July 2024 400 400 Emera - Unsecured non-revolving credit facility February 2024 400 - NMGC - Unsecured non-revolving credit facility March 2024 30 108 ECI – revolving credit facilities October 2024 10 11 Total $ 3,197 $ 2,219 Less: Borrowings under credit facilities 1,884 1,396 Letters of credit issued inside credit facilities 6 12 Use of available facilities $ 1,890 $ 1,408 Available capacity under existing agreements $ 1,307 $ 811 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 Debt Covenants Emera and its subsidiaries have debt covenants associated with their credit facilities. Covenants are tested regularly and the Company is in compliance with covenant requirements. Emera’s significant covenants are listed below: As at Financial Covenant Requirement December 31, 2023 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 Recent Significant Financing Activity by Segment Florida Electric Utility On January 30, 2024, TEC issued $ 500 4.90 per cent with a maturity date of March 1, 2029 . Proceeds from the issuance were primarily used for repayment of short-term borrowings outstanding under the 5 -year credit facility. Therefore, $ 497 USD of short-term borrowings that were repaid was classified as long-term debt at December 31, 2023. Canadian Electric Utilities On March 24, 2023, NSPI issued $ 500 300 unsecured notes that bear interest at 4.95 November 15, 2032 , and $ 200 million unsecured notes that bear interest at 5.36 March 24, 2053 . Gas Utilities and Infrastructure On December 19, 2023, PGS completed an issuance of $ 925 included $ 350 5.42 December 19, 2028 , $ 350 5.63 of December 19, 2033 225 5.94 maturity date of December 19, 2053 . On October 19, 2023, NMGC issued $ 100 6.36 October 19, 2033 . Other Electric Utilities On May 24, 2023, GBPC issued a $ 28 4.00 cent with a maturity date of May 24, 2028 . Other On August 18, 2023, Emera entered into a $ 400 February 19, 2024 . The credit agreement contains customary representations and warranties, events of default and financial and other covenants, and bears interest at Bankers’ Acceptances or prime rate advances, plus a margin. On February 16, 2024, Emera extended the term of this agreement to a maturity date of February 19, 2025 . On May 2, 2023, Emera issued $ 500 4.84 with a maturity date of May 2, 2030 . Long-Term Debt Maturities As at December 31, long-term debt maturities, including capital lease obligations, for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Emera $ 199 $ - $ 1,587 $ 266 $ - $ 500 $ 2,552 Emera US Finance LP 397 - 992 - - 2,248 3,637 TEC 397 - - - - 5,257 5,654 PGS - - - - 463 760 1,223 NMGC 30 - 93 - - 549 672 NMGI 198 - - - - - 198 NSPI 398 125 40 323 - 3,000 3,886 EBP - - 246 - - - 246 ECI 51 139 89 77 62 4 422 Total $ 1,670 $ 264 $ 3,047 $ 666 $ 525 $ 12,318 $ 18,490 |
Asset Retirement Obligations
Asset Retirement Obligations | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligations [Abstract] | |
Asset Retirement Obligations | 26. AROs mostly relate to reclamation of land at the thermal, hydro and combustion turbine sites; and the disposal of polychlorinated biphenyls in transmission and distribution equipment and a pipeline site. Certain hydro, transmission and distribution assets may have additional AROs that cannot be measured as these assets are expected to be used for an indefinite period and, as a result, a reasonable estimate of the FV of any related ARO cannot be made. The change in ARO for the years ended December 31 is as follows: millions of dollars 2023 2022 Balance, January 1 $ 174 $ 174 Accretion included in depreciation expense 9 9 Change in FX rate (1) 3 Additions - 1 Accretion deferred to regulatory asset (included in PP&E) 18 1 Liabilities settled (8) (1) Revisions in estimated cash flows - (13) Balance, December 31 $ 192 $ 174 |
Commitments and Contingencies
Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | 27. Commitments As at December 31, 2023, contractual commitments (excluding pensions and other post-retirement obligations, long-term debt and asset retirement obligations) for each of the next five years and in aggregate thereafter consisted of the following: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Transportation (1) $ 696 $ 495 $ 405 $ 388 $ 338 $ 2,597 $ 4,919 Purchased power (2) 274 249 263 312 312 3,435 4,845 Fuel, gas supply and storage 556 215 62 - 5 - 838 Capital projects 778 111 70 1 - - 960 Equity investment commitments (3) 240 - - - - - 240 Other 154 147 56 46 35 221 659 $ 2,698 $ 1,217 $ 856 $ 747 $ 690 $ 6,253 $ 12,461 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 134 (2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths. (3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining contributions over the life of the partnership. respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately 240 million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major maintenance. NSPI has a contractual obligation to pay NSPML for use of the Maritime Link over approximately 38 years from its January 15, 2018 in-service date. In February 2022, the UARB issued its decision and Board Order approving NSPML’s requested rate base of approximately $ 1.8 UARB approved the collection of up to $ 164 2024. The timing and amounts payable to NSPML for the remainder of the 38 -year commitment period are subject to UARB approval. Construction of the LIL is complete, and the Newfoundland Electrical System Operator confirmed the asset to be operating suitably to support reliable system operation and full functionality at 700 MW, which was validated by the Government of Canada’s Independent Engineer issuing its Commissioning Certificate on April 13, 2023. Emera has committed to obtain certain transmission rights for Nalcor, if requested, to enable it to transmit energy which is not otherwise used in Newfoundland and Labrador or Nova Scotia. Nalcor has the right to transmit this energy from Nova Scotia to New England energy markets effective August 15, 2021 and continuing for 50 years . As transmission rights are contracted, the obligations are included within “Other” in the above table. Legal Proceedings Superfund and Former Manufactured Gas Plant Sites Previously, TEC had been a potentially responsible party (“PRP”) for certain superfund sites through its Tampa through its PGS division. As a result of the separation of the PGS division into a separate legal entity, Peoples Gas System, Inc. is also now a PRP for those sites (in addition to third party PRPs for certain sites). result of the PGS legal separation, the sites continue to present the potential for significant response costs. As at December 31, 2023, the aggregate financial liability of the Florida utilities is estimated to be $ 15 11 credit-worthy entities. This amount has been accrued and is primarily reflected in the long-term liability section under “Other long-term liabilities” on the Consolidated Balance Sheets. The environmental remediation costs associated with these sites are expected to be paid over many years. The estimated amounts represent only the portion of the cleanup costs attributable to the Florida utilities. The estimates to perform the work are based on the Florida utilities’ experience with similar work, adjusted for site-specific conditions and agreements with the respective governmental agencies. The estimates are made in current dollars, are not discounted and do not assume any insurance recoveries. In instances where other PRPs are involved, most of those PRPs are believed to be currently credit- worthy and are likely to continue to be credit-worthy for the duration of the remediation work. However, in those instances that they are not, the Florida utilities could be liable for more than their actual percentage of the remediation costs. Other factors that could impact these estimates include additional testing and investigation which could expand the scope of the cleanup activities, additional liability that might arise from the cleanup activities themselves or changes in laws or regulations that could require additional remediation. Under current regulations, these costs are recoverable through customer rates established in base rate proceedings. Other Legal Proceedings Emera and its subsidiaries may, from time to time, be involved in other legal proceedings, claims and litigation that arise in the ordinary course of business which the Company believes would not reasonably be expected to have a material adverse effect on the financial condition of the Company. Principal Financial Risks and Uncertainties Emera believes the following principal financial risks could materially affect the Company in the normal course of business. Risks associated with derivative instruments and FV measurements are discussed in note 15 and note 16. Sound risk management is an essential discipline for running the business efficiently and pursuing the Company’s strategy successfully. Emera has an enterprise-wide risk management process, overseen by its Enterprise Risk Management Committee (“ERMC”) and monitored by the Board of Directors, to ensure an effective, consistent and coherent approach to risk management. The Board of Directors has a Risk and Sustainability Committee (‘RSC”) with a mandate that includes oversight of the Company’s Enterprise Risk Management framework, including the identification, assessment, monitoring and management of enterprise risks. It also includes oversight of the Company’s approach to sustainability and its performance relative to its sustainability objectives. Regulatory and Political Risk The Company’s rate-regulated subsidiaries and certain investments subject to significant influence are subject to risk of the recovery of costs and investments. Regulatory and political risk can include changes in regulatory frameworks, shifts in government policy, legislative changes, and regulatory decisions. As cost-of-service utilities with an obligation to serve customers, Emera’s utilities operate under formal regulatory frameworks, and must obtain regulatory approval to change or add rates and/or riders. Emera also holds investments in entities in which it has significant influence, and which are subject to regulatory and political risk including NSPML, LIL, and M&NP. Brunswick Pipeline are regulated by the CER on a complaint basis, as opposed to the regulatory approval process described above. In the absence of a complaint, the CER does not normally undertake a detailed examination of Brunswick Pipeline’s tolls, which are subject to a firm service agreement, expiring in 2034, with Repsol Energy North America Canada Partnership. Regulators administer the regulatory frameworks covering material aspects of the utilities’ businesses, including applying market-based tests to determine the appropriate customer rates and/or riders, the underlying allowed ROEs, deemed capital structures, capital investment, the terms and conditions for the provision of service, performance standards, and affiliate transactions. Regulators also review the prudency of costs and other decisions that impact customer rates and reliability of service and work to ensure the financial health of the utility for the benefit of customers. Costs and investments can be recovered upon approval by the respective regulator as an adjustment to rates and/or riders, which normally require a public hearing process or may be mandated by other governmental bodies. public hearing processes, consultants and customer representatives scrutinize the costs, actions and plans of these rate-regulated companies, and their respective regulators determine whether to allow recovery and to adjust rates based upon the evidence and any contrary evidence from other parties. In some circumstances, other government bodies may influence the setting of rates. Regulatory decisions, legislative changes, and prolonged delays in the recovery of costs or regulatory assets could result in decreased rate affordability for customers and could materially affect Emera and its utilities. Emera’s utilities generally manage this risk through transparent regulatory disclosure, ongoing stakeholder and government consultation and multi-party engagement on aspects such as utility operations, regulatory audits, rate filings and capital plans. The subsidiaries work to establish collaborative relationships with regulatory stakeholders, including customer representatives, both through its approach to filings and additional efforts with technical conferences and, where appropriate, negotiated settlements. Changes in government and shifts in government policy and legislation can impact the commercial and regulatory frameworks under which Emera and its subsidiaries operate. This includes initiatives regarding deregulation or restructuring of the energy industry. Deregulation or restructuring of the energy industry may result in increased competition and unrecovered costs that could adversely affect the Company’s operations, net income and cash flows. State and local policies in some United States jurisdictions have sought to prevent or limit the ability of utilities to provide customers the choice to use natural gas while in other jurisdictions policies have been adopted to prevent limitations on the use of natural gas. Changes in applicable state or local laws and regulations, including electrification legislation, could adversely impact PGS and NMGC. Emera cannot predict future legislative, policy, or regulatory changes, whether caused by economic, political or other factors, or its ability to respond in an effective and timely manner or the resulting compliance costs. Government interference in the regulatory process can undermine regulatory stability, predictability, and independence, and could have a material adverse effect on the Company. Foreign Exchange Risk The Company is exposed to foreign currency exchange rate changes. Emera operates internationally, with an increasing amount of the Company’s net income earned outside of Canada. As such, Emera is exposed to movements in exchange rates between the CAD and, particularly, the USD, which could positively or adversely affect results. Consistent with the Company’s risk management policies, Emera manages currency risks through matching United States denominated debt to finance its United States operations and may use foreign currency derivative instruments to hedge specific transactions and earnings exposure. The Company may enter FX forward and swap contracts to limit exposure on certain foreign currency transactions such as fuel purchases, revenue streams and capital expenditures, and on net income earned outside of Canada. The regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred costs, including FX. The Company does not utilize derivative financial instruments for foreign currency trading or speculative purposes or to hedge the value of its investments in foreign subsidiaries. Exchange gains and losses on net investments in foreign subsidiaries do not impact net income as they are reported in AOCI. Liquidity and Capital Market Risk Liquidity risk relates to Emera’s ability to ensure sufficient funds are available to meet its financial obligations. Emera manages this risk by forecasting cash requirements on a continuous basis to determine whether sufficient funds are available. Liquidity and capital needs could be financed through internally generated cash flows, asset sales, short-term credit facilities, and ongoing access to capital markets. Emera’s access to capital and cost of borrowing is subject to several risk factors, including financial market conditions, market disruptions and ratings assigned by various market analysts, including credit rating agencies. Disruptions in capital markets could prevent Emera from issuing new securities or cause the Company to issue securities with less than preferred terms and conditions. Emera’s growth plan requires significant capital investments in PP&E and the risk associated with changes in interest rates could have an adverse effect on the cost of financing. The Company’s future access to capital and cost of borrowing may be impacted by various market disruptions. The inability to access cost-effective capital could have a material impact on Emera’s ability to fund its growth plan. Emera is subject to financial risk associated with changes in its credit ratings. There are a number of factors that rating agencies evaluate to determine credit ratings, including the Company’s business, its regulatory framework and legislative environment, political interference in the regulatory process, the ability to recover costs and earn returns, diversification, leverage, liquidity and increased exposure to climate change-related impacts, including increased frequency and severity of hurricanes and other severe weather events. A decrease in a credit rating could result in higher interest rates in future financings, increased borrowing costs under certain existing credit facilities, limit access to the commercial paper market, or limit the availability of adequate credit support for subsidiary operations. For more information on interest rate risk, refer to “General Economic Risk – Interest Rate Risk”. For certain derivative instruments, if the credit ratings of the Company were reduced below investment grade, the full value of the net liability of these positions could be required to be posted as collateral. Emera manages these risks by actively monitoring and managing key financial metrics with the objective of sustaining investment grade credit ratings. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to reduce the earnings volatility derived from stock-based compensation. General Economic Risk The Company has exposure to the macro-economic conditions in North America and in other geographic regions in which Emera operates. Like most utilities, economic factors such as consumer income, employment and housing affect demand for electricity and natural gas, and in turn the Company’s financial results. Adverse changes in general economic conditions and inflation may impact the ability of customers to afford rate increases arising from increases to fuel, operating, capital, environmental compliance, and other costs, and therefore could materially affect Emera and its utilities. This may also result in higher credit and counterparty risk, adverse shifts in government policy and legislation, and/or increased risk to full and timely recovery of costs and regulatory assets. Interest Rate Risk: Emera utilizes a combination of fixed and floating rate debt financing for operations and capital expenditures, resulting in an exposure to interest rate risk. Emera seeks to manage interest rate risk through a portfolio approach that includes the use of fixed and floating rate debt with staggered maturities. The Company will, from time to time, issue long-term debt or enter interest rate hedging contracts to limit its exposure to fluctuations in floating interest rate debt. For Emera’s regulated subsidiaries, the cost of debt is a component of rates and prudently incurred debt costs are recovered from customers. Regulatory ROE will generally follow the direction of interest rates, such that regulatory ROEs are likely to fall in times of reducing interest rates and rise in times of increasing interest rates, albeit not directly and generally with a lag period reflecting the regulatory process. Rising interest rates may also negatively affect the economic viability of project development and acquisition initiatives. Interest rates could also be impacted by changes in credit ratings. For more information, refer to “Liquidity and Capital Market Risk”. As with most other utilities and other similar yield-returning investments, Emera’s share price may be affected by changes in interest rates and could underperform the market in an environment of rising interest rates. Inflation Risk: The Company may be exposed to changes in inflation that may result in increased operating and maintenance costs, capital investment, and fuel costs compared to the revenues provided by customer rates. Emera’s utilities have budgeting and forecasting processes to identify inflationary risk factors and measure operating performance, as well as collective bargaining agreements that mitigate the short-term impact of inflation on labour costs of unionized employees. Commodity Price Risk The Company’s utility fuel supply and purchase of other commodities is subject to commodity price risk. In addition, Emera Energy is subject to commodity price risk through its portfolio of commodity contracts and arrangements. The Company manages this risk through established processes and practices to identify, monitor, report and mitigate these risks. These include the Company’s commercial arrangements, such as the combination of supply and purchase agreements, asset management agreements, pipeline transportation agreements and financial hedging instruments. In addition, its credit policies, counterparty credit assessments, market and credit position reporting, and other risk management and reporting practices, are also used to manage and mitigate this risk. Regulated Utilities: The Company’s utility fuel supply is exposed to broader global conditions, which may include impacts on delivery reliability and price, despite contracted terms. Supply and demand dynamics in fuel markets can be affected by a wide range of factors which are difficult to predict and may change rapidly, including but not limited to currency fluctuations, changes in global economic conditions, natural disasters, transportation or production disruptions, and geo-political risks such as political instability, conflicts, changes to international trade agreements, trade sanctions or embargos. The Company seeks to manage this risk using financial hedging instruments and physical contracts and through contractual protection with counterparties, where applicable. The majority of Emera’s regulated electric and gas utilities have adopted and implemented fuel adjustment mechanisms and purchased gas adjustment mechanisms respectively, which further helps manage commodity price risk, as the regulatory framework for the Company’s rate-regulated subsidiaries permits the recovery of prudently incurred fuel and gas costs. There is no assurance that such mechanisms and regulatory frameworks will continue to exist in the future. Prolonged and substantial increases in fuel prices could result in decreased rate affordability, increased risk of recovery of costs or regulatory assets, and/or negative impacts on customer consumption patterns and sales. Emera Energy Marketing and Trading: Emera Energy has employed further measures to manage commodity risk. The majority of Emera Energy’s portfolio of electricity and gas marketing and trading contracts and, in particular, its natural gas asset management arrangements, are contracted on a back-to-back basis, avoiding any material long or short commodity positions. However, the portfolio is subject to commodity price risk, particularly with respect to basis point differentials between relevant markets in the event of an operational issue or counterparty default. Changes in commodity prices can also result in increased collateral requirements associated with physical contracts and financial hedges, resulting in higher liquidity requirements and increased costs to the business. To including an estimated VaR analysis of its exposures. The VaR potential change in FV that could occur from changes in Emera Energy’s portfolio or changes in market factors within a given confidence level, if an instrument or portfolio is held for a specified time period. The VaR calculation is used to quantify exposure to market risk associated with physical commodities, primarily natural gas and power positions. Income Tax Risk The computation of the Company’s provision for income taxes is impacted by changes in tax legislation in Canada, the United States and the Caribbean. Any such changes could affect the Company’s future earnings, cash flows, and financial position. The value of Emera’s existing deferred income tax assets and liabilities are determined by existing tax laws and could be negatively impacted by changes in laws. Emera monitors the status of existing tax laws to ensure that changes impacting the Company are appropriately reflected in the Company’s tax compliance filings and financial results. Guarantees and Letters of Credit Emera has guarantees and letters of credit on behalf of third parties outstanding. The following significant guarantees and letters of credit are not included within the Consolidated Balance Sheets as at December 31, 2023 : TECO Energy has issued a guarantee in connection with SeaCoast’s performance of obligations under a gas transportation precedent agreement. The guarantee is for a maximum potential amount of $ 45 USD if SeaCoast fails to pay or perform under the contract. The guarantee expires five years after the gas transportation precedent agreement termination date, which was terminated on January 1, 2022. In the event that TECO Energy’s and Emera’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s Investor Services (“Moody’s”) or S&P Global Ratings (“S&P”). TECO Energy would be required to provide its counterparty a letter of credit or cash deposit of $ 27 TECO Energy issued a guarantee in connection with SeaCoast’s performance obligations under a firm service agreement, which expires on December 31, 2055, subject to two extension terms at the option of the counterparty with a final expiration date of December 31, 2071. The guarantee is for a maximum potential amount of $ 13 In the event that TECO Energy’s long-term senior unsecured credit ratings are downgraded below investment grade by Moody’s or S&P, from an affiliate with an investment grade credit rating or a letter of credit or cash deposit of $ 13 USD. Emera Inc. has issued a guarantee of $ 66 guarantee will automatically terminate on the date upon which the obligations have been repaid in full. NSPI has issued guarantees on behalf of its subsidiary, NS Power Energy Marketing Incorporated, in the amount of $ 104 119 The Company has standby letters of credit and surety bonds in the amount of $ 103 (December 31, 2022 – $ 145 subsidiaries. These letters of credit and surety bonds typically have a one-year term and are renewed annually as required. Emera Inc., on behalf of NSPI, has a standby letter of credit to secure obligations under a supplementary retirement plan. The expiry date of this letter of credit was extended to June 2024. The amount committed as at December 31, 2023 was $ 56 63 Collaborative Arrangements For the years ended December 31, 2023 and 2022, the Company has identified the following material collaborative arrangements: Through NSPI, the Company is a participant in three wind energy projects in Nova Scotia. The percentage ownership of the wind project assets is based on the relative value of each party’s project assets by the total project assets. NSPI has power purchase arrangements to purchase the entire net output of the projects and, therefore, NSPI’s portion of the revenues are recorded net within regulated fuel for generation and purchased power. NSPI’s portion of operating expenses is recorded in “OM&G” on the Consolidated Statements of Income. In 2023, NSPI recognized $ 8 12 million) in “Regulated fuel for generation and purchased power” and $ 3 3 “OM&G” on the Consolidated Statements of Income. |
Cumulative Preferred Stock
Cumulative Preferred Stock | 12 Months Ended |
Dec. 31, 2023 | |
Cumulative Preferred Stock [Abstract] | |
Cumulative Preferred Stock | 28. Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2023 December 31, 2022 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.6085 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.5810 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.6085 2.65 August 15, 2028 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A (5)(7) 4.900 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (9) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 25.00 share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.90 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series 2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. (6) The annual fixed dividend per share for Series C Shares was reset from $ 1.1802 1.6085 including August 15, 2028. (7) The annual fixed dividend per share for Series H Shares was reset from $ 1.2250 1.5810 including August 15, 2028. (8) First Preferred Shares, Series E are redeemable at $25.00 per share. (9) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00 First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in Sub
Non-Controlling Interest in Subsidiaries | 12 Months Ended |
Dec. 31, 2023 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Non-Controlling Interest in Subsidiaries | 29. As at December 31 December 31 millions of dollars 2023 2022 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14 Preferred shares of GBPC: Authorized: 10,000 2023 2022 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 GBPC Non–Voting Cumulative Variable Perpetual Preferred Stock: The preferred shares are redeemable by GBPC after June 17, 2021 , at $ 1,000 accrued and unpaid dividends and are entitled to a 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually . The Preferred Shares rank behind GBPC’s current and future secured and unsecured debt and ahead of all of GBPC’s current and future common stock. |
Supplementary Information to Co
Supplementary Information to Consolidated Statements of Cash Flows | 12 Months Ended |
Dec. 31, 2023 | |
Supplementary Information to Consolidated Statements of Cash Flows [Abstract] | |
Supplementary Information to Consolidated Statements of Cash Flows | 30. SUPPLEMENTARY CASH FLOWS For the Year ended December 31 millions of dollars 2023 2022 Changes in non-cash working capital: $ (31) $ (214) (1) 653 (636) (538) 423 (2) (179) 193 Total non-cash working capital $ (95) $ (234) (1) Includes $ 162 162 ) million). Offsetting regulatory liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes ($ 166 ) million related to the Nova Scotia Cap-and-Trade program (2022 – $ 172 6. Offsetting regulatory asset (FAM) balance is cash provided by operating activities. For the Year ended December 31 millions of dollars 2023 2022 Supplemental disclosure of cash paid: Interest $ 930 $ 699 Income taxes $ 43 $ 67 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 271 $ 237 Decrease in accrued capital expenditures $ (19) $ (13) Reclassification of short-term debt to long-term debt $ 657 $ - Reclassification of long-term debt to short-term debt $ - $ 500 Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ 123 $ (157) |
Stock Based Compensation
Stock Based Compensation | 12 Months Ended |
Dec. 31, 2023 | |
Stock-Based Compensation [Abstract] | |
Stock-based Compensation | 31. Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. maximum aggregate number of Emera common shares reserved for issuance under this plan is 7 common shares. As at December 31, 2023, Emera was in compliance with this requirement. Compensation cost for shares issued under the ECSPP for the year ended December 31, 2023 was $ 3 million (2022 – $ 3 The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. Stock-Based Compensation Plans Stock Option Plan The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. For stock options granted in 2021 and prior, unless a stock option has expired, vested options may be exercised within the 27 months six months termination without just cause or death, and within sixty days cause or resignation. Commencing with the 2022 stock option grant, vested options may be exercised during the full term of the option following the option holders date of retirement, six months termination without just cause or death, and within sixty days cause or resignation. If stock options are not exercised within such time, they expire. The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. The following table shows the weighted average FV per stock option along with the assumptions incorporated into the valuation models for options granted, for the year-ended December 31: 2023 2022 Weighted average FV per option $ 6.32 $ 5.35 Expected term (1) 5 5 Risk-free interest rate (2) 3.53 % 1.79 % Expected dividend yield (3) 5.05 % 4.55 % Expected volatility (4) 20.07 % 18.87 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility. The following table summarizes stock option information for 2023: Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Granted 483,100 54.64 483,100 6.32 Exercised (146,475) 43.94 N/A N/A Forfeited (94,900) 56.32 (51,625) 3.61 Vested N/A N/A (526,620) 3.58 Options outstanding December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Options exercisable December 31, 2023 (2)(3) 1,842,349 $ 48.39 (1) As at December 31, 2023, there was $ 5 expected to be recognized over a weighted average period of approximately 3 4 3 (2) As at December 31, 2023, the weighted average remaining term of vested options was 5 $ 8 5 10 (3) As at December 31, 2023, the FV of options that vested in the year was $ 2 2 Compensation cost recognized for stock options for the year ended December 31, 2023 was $ 2 (2022 – $ 2 As at December 31, 2023, cash received from option exercises was $ 6 9 total intrinsic value of options exercised for the year ended December 31, 2023 was $ 2 4 million). The range of exercise prices for the options outstanding as at December 31, 2023 was $ 32.35 $ 60.03 32.35 60.03 ). Share Unit Plans The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. Deferred Share Unit Plans Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. A summary of the activity related to employee and director DSUs for the year ended December 31, 2023 is presented in the following table: Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83 Granted including DRIP 85,740 47.66 117,893 49.99 Exercised N/A N/A (53,093) 49.39 Outstanding and exercisable as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 Compensation cost recovery recognized for employee and director DSU’s for the year ended December 31, 2023 was $ 2 6 share units realized for the year ended December 31, 2023 was $ 1 2 aggregate intrinsic value of the outstanding shares for the year ended December 31, 2023 for employees was $ 36 33 ended December 31, 2023 for directors was $ 37 34 during the year ended December 31, 2023 associated with the DSU plan were $ 3 8 million). Performance Share Unit Plan Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee PSUs for the year ended December 31, 2023 is presented in the following table: Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Granted including DRIP 386,261 52.71 Exercised (323,155) 54.62 Forfeited (10,187) 55.15 Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 Compensation cost recognized for the PSU plan for the year ended December 31, 2023 was $ 11 (2022 – $ 18 ended December 31, 2023 were $ 3 5 ended December 31, 2023 associated with the PSU plan were $ 19 24 Restricted Share Unit Plan Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement. A summary of the activity related to employee RSUs for the year ended December 31, 2023 is presented in the following table: Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30 Granted including DRIP 236,537 52.07 Exercised (171,537) 54.62 Forfeited (10,827) 54.76 Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 Compensation cost recognized for the RSU plan for the year ended December 31, 2023 was $ 10 (2022 – $ 9 ended December 31, 2023 were $ 3 2 ended December 31, 2023 associated with the RSU plan were $ 10 nil ). |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2023 | |
Variable Interest Entities [Abstract] | |
Variable Interest Entities | 32. Emera holds a variable interest in NSPML, a VIE for which it was determined that Emera is not the primary beneficiary since it does not have the controlling financial interest of NSPML. When the critical milestones were achieved, Nalcor Energy was deemed the primary beneficiary of the asset for financial reporting purposes as it has authority over the majority of the direct activities that are expected to most significantly impact the economic performance of the Maritime Link. Thus, Emera began recording the Maritime Link as an equity investment. BLPC has established a SIF, primarily for the purpose of building a fund to cover risk against damage and consequential loss to certain generating, transmission and distribution systems. ECI holds a variable interest in the SIF for which it was determined that ECI was the primary beneficiary and, accordingly, the SIF must be consolidated by ECI. In its determination that ECI controls the SIF, management considered that, in substance, the activities of the SIF are being conducted on behalf of ECI’s subsidiary BLPC and BLPC, alone, obtains the benefits from the SIF’s operations. Additionally, because ECI, through BLPC, has rights to all the benefits of the SIF, it is also exposed to the risks related to the activities of the SIF. Any withdrawal of SIF fund assets by the Company would be subject to existing regulations. Emera’s consolidated VIE in the SIF is recorded as “Other long-term assets”, “Restricted cash” and “Regulatory liabilities” on the Consolidated Balance Sheets. Amounts included in restricted cash represent the cash portion of funds required to be set aside for the BLPC SIF. The Company has identified certain long-term purchase power agreements that meet the definition of variable interests as the Company has to purchase all or a majority of the electricity generation at a fixed price. However, it was determined that the Company was not the primary beneficiary since it lacked the power to direct the activities of the entity, including the ability to operate the generating facilities and make management decisions. The following table provides information about Emera’s portion of material unconsolidated VIEs: As at December 31, 2023 December 31, 2022 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 489 $ 6 $ 501 $ 6 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2023 | |
Subsequent Events [Abstract] | |
Subsequent Events | 33. These financial statements and notes reflect the Company’s evaluation of events occurring subsequent to the balance sheet date through February 26, 2024, the date the financial statements were issued. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Summary of Significant Accounting Policies [Abstract] | |
Basis of Presentation | Basis of Presentation These consolidated financial statements are prepared and presented in accordance with United States Generally Accepted Accounting Principles (“USGAAP”) and in the opinion of management, include all adjustments that are of a recurring nature and necessary to fairly state the financial position of Emera. All dollar amounts are presented in Canadian dollars (“CAD”), unless otherwise indicated. |
Principles of Consolidation | Principles of Consolidation These consolidated financial statements include the accounts of Emera Incorporated, its majority-owned subsidiaries, and a variable interest entity (“VIE”) in which Emera is the primary beneficiary. Emera uses the equity method of accounting to record investments in which the Company has the ability to exercise significant influence, and for VIEs in which Emera is not the primary beneficiary. The Company performs ongoing analysis to assess whether it holds any VIEs or whether any reconsideration events have arisen with respect to existing VIEs. To identify potential VIEs, management reviews contractual and ownership arrangements such as leases, long-term purchase power agreements, tolling contracts, guarantees, jointly owned facilities and equity investments. VIEs of which the Company is deemed the primary beneficiary must be consolidated. The primary beneficiary of a VIE has both the power to direct the activities of the VIE that most significantly impacts its economic performance and the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE. In circumstances where Emera has an investment in a VIE but is not deemed the primary beneficiary, the VIE is accounted for using the equity method. For further details on VIEs, refer to note 32. Intercompany balances and transactions have been eliminated on consolidation, except for the net profit on certain transactions between certain non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The net profit on these transactions, which would be eliminated in the absence of the accounting standards for rate-regulated entities, is recorded in non- regulated operating revenues. An offset is recorded to PP&E, regulatory assets, regulated fuel for generation and purchased power, or OM&G, depending on the nature of the transaction. |
Use of Management Estimates | Use of Management Estimates The preparation of consolidated financial statements in accordance with USGAAP requires management to make estimates and assumptions. These may affect reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting periods. Significant areas requiring use of management estimates relate to rate-regulated assets and liabilities, accumulated reserve for cost of removal, pension and post-retirement benefits, unbilled revenue, useful lives for depreciable assets, goodwill and long-lived assets impairment assessments, income taxes, asset retirement obligations (“ARO”), and valuation of financial instruments. Management evaluates the Company’s estimates on an ongoing basis based upon historical experience, current and expected conditions and assumptions believed to be reasonable at the time the assumption is made, with any adjustments recognized in income in the year they arise. |
Regulatory Matters | Regulatory Matters Regulatory accounting applies where rates are established by, or subject to approval by, an third-party regulator. Rates are designed to recover prudently incurred costs of providing regulated products or services and provide an opportunity for a reasonable rate of return on invested capital, as applicable. For further detail, refer to note 6. |
Foreign Currency Translation | Foreign Currency Translation Monetary assets and liabilities denominated in foreign currencies are converted to CAD at the rates of exchange prevailing at the balance sheet date. The resulting differences between the translation at the original transaction date and the balance sheet date are included in income. Assets and liabilities of foreign operations whose functional currency is not the Canadian dollar are translated using exchange rates in effect at the balance sheet date and the results of operations at the average exchange rate in effect for the period. The resulting exchange gains and losses on the assets and liabilities are deferred on the balance sheet in AOCI. The Company designates certain USD denominated debt held in CAD functional currency companies as hedges of net investments in USD denominated foreign operations. The change in the carrying amount of these investments, measured at exchange rates in effect at the balance sheet date is recorded in Other Comprehensive Income (“OCI”). |
Revenue Recognition | Revenue Recognition Regulated Electric and Gas Revenue: Electric and gas revenues, including energy charges, demand charges, basic facilities charges and clauses and riders, are recognized when obligations under the terms of a contract are satisfied, which is when electricity and gas are delivered to customers over time as the customer simultaneously receives and consumes the benefits. Electric and gas revenues are recognized on an accrual basis and include billed and unbilled revenues. Revenues related to the sale of electricity and gas are recognized at rates approved by the respective regulators and recorded based on metered usage, which occurs on a periodic, systematic basis, generally monthly or bi-monthly. At the end of each reporting period, electricity and gas delivered to customers, but not billed, is estimated and corresponding unbilled revenue is recognized. The Company’s estimate of unbilled revenue at the end of the reporting period is calculated by estimating the megawatt hours (“MWh”) or therms delivered to customers at the established rates expected to prevail in the upcoming billing cycle. This estimate includes assumptions as to the pattern of energy demand, weather, line losses and inter-period changes to customer classes. Non-regulated Revenue: Marketing and trading margins are comprised of Emera Energy’s corresponding purchases and sales of natural gas and electricity, pipeline capacity costs and energy asset management revenues. Revenues are recorded when obligations under terms of the contract are satisfied and are presented on a net basis reflecting the nature of contractual relationships with customers and suppliers. Energy sales are recognized when obligations under the terms of the contracts are satisfied, which is when electricity is delivered to customers over time. Other non-regulated revenues are recorded when obligations under the terms of the contract are satisfied. Other: Sales, value add, and other taxes, except for gross receipts taxes discussed below, collected by the Company concurrent with revenue-producing activities are excluded from revenue. |
Franchise Fees and Gross Receipts | Franchise Fees and Gross Receipts TEC and PGS recover from customers certain costs incurred, on a dollar-for-dollar basis, through prices approved by the Florida Public Service Commission (“FPSC”). The amounts included in customers’ bills for franchise fees and gross receipt taxes are included as “Regulated electric” and “Regulated gas” revenues in the Consolidated Statements of Income. Franchise fees and gross receipt taxes payable by TEC and PGS are included as an expense on the Consolidated Statements of Income in “Provincial, state and municipal taxes”. NMGC is an agent in the collection and payment of franchise fees and gross receipt taxes and is not required by a tariff to present the amounts on a gross basis. Therefore, NMGC’s franchise fees and gross receipt taxes are presented net with no line item impact on the Consolidated Statements of Income. |
PP&E | PP&E PP&E is recorded at original cost, including AFUDC or capitalized interest, net of contributions received in aid of construction. The cost of additions, including betterments and replacements of units, are included in “PP&E” on the Consolidated Balance Sheets. When units of regulated PP&E are replaced, renewed or retired, their cost, plus removal or disposal costs, less salvage proceeds, is charged to accumulated depreciation, with no gain or loss reflected in income. Where a disposition of non-regulated PP&E occurs, gains and losses are included in income as the dispositions occur. The cost of PP&E represents the original cost of materials, contracted services, direct labour, AFUDC for regulated property or interest for non-regulated property, ARO, and overhead attributable to the capital project. Overhead includes corporate costs such as finance, information technology and labour costs, along with other costs related to support functions, employee benefits, insurance, procurement, and fleet operating and maintenance. Expenditures for project development are capitalized if they are expected to have a future economic benefit. Normal maintenance projects and major maintenance projects that do not increase overall life of the related assets are expensed as incurred. When a major maintenance project increases the life or value of the underlying asset, the cost is capitalized. Depreciation is determined by the straight-line method, based on the estimated remaining service lives of the depreciable assets in each functional class of depreciable property. For some of Emera’s rate- regulated subsidiaries, depreciation is calculated using the group remaining life method, which is applied to the average investment, adjusted for anticipated costs of removal less salvage, in functional classes of depreciable property. The service lives of regulated assets require regulatory approval. Intangible assets, which are included in “PP&E” on the Consolidated Balance Sheets, consist primarily of computer software and land rights. Amortization is determined by the straight-line method, based on the estimated remaining service lives of the asset in each category. For some of Emera’s rate-regulated subsidiaries, amortization is calculated using the amortizable life method which is applied to the net book value to date over the remaining life of those assets. The service lives of regulated intangible assets require regulatory approval. |
Goodwill | Goodwill Goodwill is calculated as the excess of the purchase price of an acquired entity over the estimated FV of identifiable assets acquired and liabilities assumed at the acquisition date. Goodwill is carried at initial cost less any write-down for impairment and is adjusted for the impact of foreign exchange (“FX”). Goodwill is subject to assessment for impairment at the reporting unit level annually, or if an event or change in circumstances indicates that the FV of a reporting unit may be below its carrying value. When assessing goodwill for impairment, the Company has the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment management considers, among other factors, macroeconomic conditions, industry and market considerations and overall financial performance. If the Company performs a qualitative assessment and determines it is more likely than not that its FV is less than its carrying amount, or if the Company chooses to bypass the qualitative assessment, a quantitative test is performed. The quantitative test compares the FV of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its FV, an impairment loss is recorded. Management estimates the FV of the reporting unit by using the income approach, or a combination of the income and market approach. The income approach uses a discounted cash flow analysis which relies on management’s best estimate of the reporting unit’s projected cash flows. The analysis includes an estimate of terminal values based on these expected cash flows using a methodology which derives a valuation using an assumed perpetual annuity based on the reporting unit’s residual cash flows. The discount rate used is a market participant rate based on a peer group of publicly traded comparable companies and represents the weighted average cost of capital of comparable companies. For the market approach, management estimates FV based on comparable companies and transactions within the utility industry. Significant assumptions used in estimating the FV of a reporting unit using an income approach include discount and growth rates, rate case assumptions including future cost of capital, valuation of the reporting unit’s net operating loss (“NOL”) and projected operating and capital cash flows. Adverse changes in these assumptions could result in a future material impairment of the goodwill assigned to Emera’s reporting units. As of December 31, 2023, $ 5,868 purchase price for TECO Energy (TEC, PGS and NMGC reporting units) over the FV assigned to identifiable assets acquired and liabilities assumed. In Q4 2023, qualitative assessments were performed for NMGC and PGS given the significant excess of FV over carrying amounts calculated during the last quantitative tests in Q4 2022 and Q4 2019, respectively. Management concluded it was more likely than not that the FV of these reporting units exceeded their respective carrying amounts, including goodwill. As such, no quantitative testing was required. Given the length of time passed since the last quantitative impairment test for the TEC reporting unit, Emera elected to bypass a qualitative assessment and performed a quantitative impairment assessment in Q4 2023 using a combination of the income and market approach. This assessment estimated that the FV of the TEC reporting unit exceeded its carrying amount, including goodwill, and as a result, no impairment charges were recognized. In Q4 2022, as a result of a quantitative assessment, the Company recorded a goodwill impairment charge of $ 73 nil details, refer to note 22. |
Income Taxes and Investment Tax Credits | Income Taxes and Investment Tax Emera recognizes deferred income tax assets and liabilities for the future tax consequences of events that have been included in financial statements or income tax returns. Deferred income tax assets and liabilities are determined based on the difference between the carrying value of assets and liabilities on the Consolidated Balance Sheets, and their respective tax bases using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change is enacted, unless required to be offset to a regulatory asset or liability by law or by order of the regulator. Emera recognizes the effect of income tax positions only when it is more likely than not that they will be realized. Management reviews all readily available current and historical information, including forward- looking information, and the likelihood that deferred income tax assets will be recovered from future taxable income is assessed and assumptions are made about the expected timing of reversal of deferred income tax assets and liabilities. If management subsequently determines it is likely that some or all of a deferred income tax asset will not be realized, a valuation allowance is recorded to reflect the amount of deferred income tax asset expected to be realized. Generally, investment tax credits are recorded as a reduction to income tax expense in the current or future periods to the extent that realization of such benefit is more likely than not. Investment tax credits earned on regulated assets by TEC, PGS and NMGC are deferred and amortized as required by regulatory practices. TEC, PGS, NMGC and BLPC collect income taxes from customers based on current and deferred income taxes. NSPI, ENL and Brunswick Pipeline collect income taxes from customers based on income tax that is currently payable, except for the deferred income taxes on certain regulatory balances specifically prescribed by regulators. For the balance of regulated deferred income taxes, NSPI, ENL and Brunswick Pipeline recognize regulatory assets or liabilities where the deferred income taxes are expected to be recovered from or returned to customers in future years. These regulated assets or liabilities are grossed up using the respective income tax rate to reflect the income tax associated with future revenues that are required to fund these deferred income tax liabilities, and the income tax benefits associated with reduced revenues resulting from the realization of deferred income tax assets. GBPC is not subject to income taxes. Emera classifies interest and penalties associated with unrecognized tax benefits as interest and operating expense, respectively. For further detail, refer to note 10. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities The Company manages its exposure to normal operating and market risks relating to commodity prices, FX, interest rates and share prices through contractual protections with counterparties where practicable, and by using financial instruments consisting mainly of FX forwards and swaps, interest rate options and swaps, equity derivatives, and coal, oil and gas futures, options, forwards and swaps. In addition, the Company has contracts for the physical purchase and sale of natural gas. These physical and financial contracts are classified as HFT. Collectively, derivatives. The Company recognizes the FV of all its derivatives on its balance sheet, except for non-financial derivatives that meet the normal purchases and normal sales (“NPNS”) exception. Physical contracts that meet the NPNS exception are not recognized on the balance sheet; these contracts are recognized in income when they settle. A physical contract generally qualifies for the NPNS exception if the transaction is reasonable in relation to the Company’s business needs, the counterparty owns or controls resources within the proximity to allow for physical delivery, the Company intends to receive physical delivery of the commodity, and the Company deems the counterparty creditworthy. contracts designated under the NPNS exception and will discontinue the treatment of these contracts under this exemption if the criteria are no longer met. Derivatives qualify for hedge accounting if they meet stringent documentation requirements and can be proven to effectively hedge identified risk both at the inception and over the term of the instrument. Specifically, for cash flow hedges, change in the FV of derivatives is deferred to AOCI and recognized in income in the same period the related hedged item is realized. Where documentation or effectiveness requirements are not met, the derivatives are recognized at FV with any changes in FV recognized in net income in the reporting period, unless deferred as a result of regulatory accounting. Derivatives entered into by NSPI, NMGC and GBPC that are documented as economic hedges or for which the NPNS exception has not been taken, are subject to regulatory accounting treatment. The change in FV of the derivatives is deferred to a regulatory asset or liability. The gain or loss is recognized in the hedged item when the hedged item is settled. Management believes any gains or losses resulting from settlement of these derivatives related to fuel for generation and purchased power will be refunded to or collected from customers in future rates. TEC has no derivatives related to hedging as a result of a FPSC approved five-year moratorium on hedging of natural gas purchases that ended on December 31, 2022 and was extended through December 31, 2024 as a result of TEC’s 2021 rate case settlement agreement. Derivatives that do not meet any of the above criteria are designated as HFT, with changes in FV normally recorded in net income of the period. The Company has not elected to designate any derivatives to be included in the HFT category where another accounting treatment would apply. Emera classifies gains and losses on derivatives as a component of non-regulated operating revenues, fuel for generation and purchased power, other expenses, inventory, and OM&G, depending on the nature of the item being economically hedged. Transportation capacity arising as a result of marketing and trading derivative transactions is recognized as an asset in “Receivables and other current assets” and amortized over the period of the transportation contract term. Cash flows from derivative activities are presented in the same category as the item being hedged within operating or investing activities on the Consolidated Statements of Cash Flows. Non-hedged derivatives are included in operating cash flows on the Consolidated Statements of Cash Flows. Derivatives, as reflected on the Consolidated Balance Sheets, are not offset by the FV amounts of cash collateral with the same counterparty. Rights to reclaim cash collateral are recognized in “Receivables and other current assets” and obligations to return cash collateral are recognized in “Accounts payable”. |
Lessee, Leases | Leases The Company determines whether a contract contains a lease at inception by evaluating whether the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Emera has leases with independent power producers (“IPP”) and other utilities for annual requirements to purchase wind and hydro energy over varying contract lengths which are classified as finance leases. These finance leases are not recorded on the Company’s Consolidated Balance Sheets as payments associated with the leases are variable in nature and there are no minimum fixed lease payments. Lease expense associated with these leases is recorded as “Regulated fuel for generation and purchased power” on the Consolidated Statements of Income. Operating lease liabilities and right-of-use assets are recognized on the Consolidated Balance Sheets based on the present value of the future minimum lease payments over the lease term at commencement date. As most of Emera’s leases do not provide an implicit rate, the incremental borrowing rate at commencement of the lease is used in determining the present value of future lease payments. Lease expense is recognized on a straight-line basis over the lease term and is recorded as “Operating, maintenance and general” on the Consolidated Statements of Income. |
Lessor, Leases | Where the Company is the lessor, a lease is a sales-type lease if certain criteria are met and the arrangement transfers control of the underlying asset to the lessee. For arrangements where the criteria are met due to the presence of a third-party residual value guarantee, the lease is a direct financing lease. For direct finance leases, a net investment in the lease is recorded that consists of the sum of the minimum lease payments and residual value, net of estimated executory costs and unearned income. The difference between the gross investment and the cost of the leased item is recorded as unearned income at the inception of the lease. Unearned income is recognized in income over the life of the lease using a constant rate of interest equal to the internal rate of return on the lease. For sales-type leases, the accounting is similar to the accounting for direct finance leases however, the difference between the FV and the carrying value of the leased item is recorded at lease commencement rather than deferred over the term of the lease. Emera has certain contractual agreements that include lease and non-lease components, which management has elected to account for as a single lease component. |
Cash, Cash Equivalents and Restricted Cash | Cash, Cash Equivalents and Restricted Cash Cash equivalents consist of highly liquid short-term investments with original maturities of three months or less at acquisition. |
Receivables | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. |
Allowance for Credit Losses | Receivables and Allowance for Credit Losses Utility customer receivables are recorded at the invoiced amount and do not bear interest. Standard payment terms for electricity and gas sales are approximately 30 days. A late payment fee may be assessed on account balances after the due date. The Company recognizes allowances for credit losses to reduce accounts receivable for amounts expected to be uncollectable. Management estimates credit losses related to accounts receivable by considering historical loss experience, customer deposits, current events, the characteristics of existing accounts and reasonable and supportable forecasts that affect the collectability of the reported amount. Provisions for credit losses on receivables are expensed to maintain the allowance at a level considered adequate to cover expected losses. Receivables are written off against the allowance when they are deemed uncollectible. |
Inventory | Inventory Fuel and materials inventories are valued at the lower of weighted-average cost or net realizable value, unless evidence indicates the weighted-average cost will be recovered in future customer rates. |
Asset Impairment | Asset Impairment Long-Lived Assets: Emera assesses whether there has been an impairment of long-lived assets and intangibles when a triggering event occurs, such as a significant market disruption or sale of a business. The assessment involves comparing undiscounted expected future cash flows to the carrying value of the asset. When the undiscounted cash flow analysis indicates a long-lived asset is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long- lived asset over its estimated FV. The Company’s assumptions relating to future results of operations or other recoverable amounts, are based on a combination of historical experience, fundamental economic analysis, observable market activity and independent market studies. The Company’s expectations regarding uses and holding periods of assets are based on internal long-term budgets and projections, which consider external factors and market forces, as of the end of each reporting period. The assumptions made are consistent with generally accepted industry approaches and assumptions used for valuation and pricing activities. As at December 31, 2023, there are no indications of impairment of Emera’s long-lived assets. No impairment charges related to long-lived assets were recognized in 2023 or 2022. Equity Method Investments: The carrying value of investments accounted for under the equity method are assessed for impairment by comparing the FV of these investments to their carrying values, if a FV assessment was completed, or by reviewing for the presence of impairment indicators. If an impairment exists, and it is determined to be other-than-temporary, a charge is recognized in earnings equal to the amount the carrying value exceeds the investment’s FV. No Financial Assets: Equity investments, other than those accounted for under the equity method, are measured at FV, with changes in FV recognized in the Consolidated Statements of Income. Equity investments that do not have readily determinable FV are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investments. No impairment of financial assets was required in either 2023 or 2022. |
Asset Retirement Obligations and Cost of Removal | Asset Retirement Obligations An ARO is recognized if a legal obligation exists in connection with the future disposal or removal costs resulting from the permanent retirement, abandonment or sale of a long-lived asset. A legal obligation may exist under an existing or enacted law or statute, written or oral contract, or by legal construction under the doctrine of promissory estoppel. An ARO represents the FV of estimated cash flows necessary to discharge the future obligation, using the Company’s credit adjusted risk-free rate. The amounts are reduced by actual expenditures incurred. Estimated future cash flows are based on completed depreciation studies, remediation reports, prior experience, estimated useful lives, and governmental regulatory requirements. The present value of the liability is recorded and the carrying amount of the related long-lived asset is correspondingly increased. The amount capitalized at inception is depreciated in the same manner as the related long-lived asset. Over time, the liability is accreted to its estimated future value. AROs are included in “Other long-term liabilities” and accretion expense is included as part of “Depreciation and amortization”. Any regulated accretion expense not yet approved by the regulator is recorded in “Property, plant and equipment” and included in the next depreciation study. Some of the Company’s transmission and distribution assets may have conditional AROs that are not recognized in the consolidated financial statements, as the FV of these obligations could not be reasonably estimated, given insufficient information to do so. A conditional ARO refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. Management monitors these obligations and a liability is recognized at FV in the period in which an amount can be determined. Cost of Removal (“COR”) TEC, PGS, NMGC and NSPI recognize non-ARO COR as regulatory liabilities. The non-ARO COR represent funds received from customers through depreciation rates to cover estimated future non-legally required COR of PP&E upon retirement. The companies accrue for COR over the life of the related assets based on depreciation studies approved by their respective regulators. The costs are estimated based on historical experience and future expectations, including expected timing and estimated future cash outlays. |
Stock-Based Compensation | Stock-Based Compensation The Company has several stock-based compensation plans: a common share option plan for senior management; an employee common share purchase plan; a deferred share unit (“DSU”) plan; a performance share unit (“PSU”) plan; and a restricted share unit (“RSU”) plan. The Company accounts for its plans in accordance with the FV-based method of accounting for stock-based compensation. Stock- based compensation cost is measured at the grant date, based on the calculated FV of the award, and is recognized as an expense over the employee’s or director’s requisite service period using the graded vesting method. Stock-based compensation plans recognized as liabilities are initially measured at FV and re-measured at FV at each reporting date, with the change in liability recognized in income. |
Employee Benefits | Employee Benefits The costs of the Company’s pension and other post-retirement benefit programs for employees are expensed over the periods during which employees render service. The Company recognizes the funded status of its defined-benefit and other post-retirement plans on the balance sheet and recognizes changes in funded status in the year the change occurs. The Company recognizes unamortized gains and losses and past service costs in “AOCI” or “Regulatory assets” on the Consolidated Balance Sheets. The components of net periodic benefit cost other than the service cost component are included in “Other income, net” on the Consolidated Statements of Income. For further detail, refer to note 21. |
Segment Information (Tables)
Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Information | Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2023 Operating revenues from external customers (1) $ 3,548 $ 1,671 $ 1,510 $ 526 $ 308 $ $ 7,563 Inter-segment revenues (1) 8 - 14 - 31 (53) 3,556 1,671 1,524 526 339 (53) 7,563 Regulated fuel for generation and purchased power 920 699 - 275 - (13) 1,881 Regulated cost of natural gas - - 527 - - - 527 OM&G 830 384 405 130 151 (21) 1,879 Provincial, state and municipal taxes 289 45 91 3 5 - 433 Depreciation and amortization 571 276 126 68 8 - 1,049 Income from equity investments - 109 21 4 12 - 146 Other income, net 69 32 11 7 20 19 158 Interest expense, net (2) 271 170 129 23 332 - 925 Income tax expense (recovery) 117 (9) 64 - (44) - 128 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 66 - 66 Net income (loss) attributable to common shareholders $ 627 $ 247 $ 214 $ 37 $ (147) $ - $ 978 Capital expenditures $ 1,736 $ 450 $ 664 $ 63 $ 8 $ - $ 2,921 As at December 31, 2023 Total assets $ 21,119 $ 8,634 $ 7,735 $ 1,311 $ 1,938 $ (1,257) $ 39,480 Investments subject to significant influence $ - $ 1,236 $ 118 $ 48 $ - $ - $ 1,402 Goodwill $ 4,628 $ - $ 1,240 $ - $ 3 $ - $ 5,871 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 95 December 31, 2023, between the Florida Electric Utility, Florida Canadian Gas Utilities Other Inter- Electric Electric and Electric Segment millions of dollars Utility Utilities Infrastructure Utilities Other Eliminations Total For the year ended December 31, 2022 Operating revenues from external customers (1) $ 3,280 $ 1,675 $ 1,697 $ 518 $ 418 $ $ 7,588 Inter-segment revenues (1) 7 - 7 - 22 (36) 3,287 1,675 1,704 518 440 (36) 7,588 Regulated fuel for generation and purchased power 1,086 803 - 290 - (8) 2,171 Regulated cost of natural gas - - 800 - - - 800 OM&G 625 338 365 123 156 (11) 1,596 Provincial, state and municipal taxes 235 43 83 3 3 - 367 Depreciation and amortization 507 259 118 61 7 - 952 Income from equity investments - 87 21 4 17 - 129 Other income (expenses), net 68 24 13 - 23 17 145 Interest expense, net (2) 185 136 81 19 288 - 709 GBPC impairment charge - - - 73 - - 73 Income tax expense (recovery) 121 (8) 70 - 2 - 185 Non-controlling interest in subsidiaries - - - 1 - - 1 Preferred stock dividends - - - - 63 - 63 Net income (loss) attributable to common shareholders $ 596 $ 215 $ 221 $ (48) $ (39) $ - $ 945 Capital expenditures $ 1,425 $ 507 $ 574 $ 63 $ 6 $ - $ 2,575 As at December 31, 2022 Total assets $ 21,053 $ 8,223 $ 7,737 $ 1,337 $ 2,835 $ (1,443) $ 39,742 Investments subject to significant influence $ - $ 1,241 $ 128 $ 49 $ - $ - $ 1,418 Goodwill $ 4,739 $ - $ 1,270 $ - $ 3 $ - $ 6,012 (1) All significant inter-company balances and transactions have been eliminated on consolidation except for certain transactions between non-regulated and regulated entities. Management believes elimination of these transactions would understate PP&E, OM&G, or regulated fuel for generation and purchased power. Inter-company measured at the amount of consideration established and agreed to by the related parties. Eliminated transactions are determining reportable segments. (2) Segment net income is reported on a basis that includes internally allocated financing costs of $ 13 December 31, 2022, between the Gas Utilities and Infrastructure and Other segments. Geographical Information Revenues (based on country of origin of the product or service sold) For the Year ended December 31 millions of dollars 2023 2022 United States 5,310 $ 5,346 Canada 1,727 1,725 Barbados 389 384 The Bahamas 137 122 Dominica - 11 $ 7,563 $ 7,588 Property Plant and Equipment: As at December 31 December 31 millions of dollars 2023 2022 United States $ 18,588 $ 17,382 Canada 4,878 4,689 Barbados 576 583 The Bahamas 334 342 $ 24,376 $ 22,996 |
Revenue (Tables)
Revenue (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue [Abstract] | |
Disaggregation of Revenue by Major Source | Electric Gas Other Florida Canadian Other Gas Utilities Inter- Electric Electric Electric and Segment millions of dollars Utility Utilities Utilities Infrastructure Other Eliminations Total For the year ended December 31, 2023 Regulated Revenue Residential $ 2,307 $ 910 $ 183 $ 724 $ - $ - $ 4,124 Commercial 1,083 463 285 425 - - 2,256 Industrial 274 219 33 93 - (13) 606 Other electric 395 41 7 - - - 443 Regulatory deferrals (522) - 12 - - - (510) Other (1) 19 38 6 199 - (8) 254 Finance income (2)(3) - - - 62 - 62 $ 3,556 $ 1,671 $ 526 $ 1,503 $ - $ (21) $ 7,235 Non-Regulated Revenue Marketing and trading margin (4) - - - - 96 - 96 Other non-regulated operating revenue - - - 21 27 (23) 25 Mark-to-market (3) - - - - 216 (9) 207 $ - $ - $ - $ 21 $ 339 $ (32) $ 328 Total operating revenues $ 3,556 $ 1,671 $ 526 $ 1,524 $ 339 $ (53) $ 7,563 For the year ended December 31, 2022 Regulated Revenue Residential $ 1,799 $ 834 $ 184 $ 800 $ - $ - $ 3,617 Commercial 869 427 282 461 - - 2,039 Industrial 230 353 32 83 - (7) 691 Other electric 398 28 6 - - - 432 Regulatory deferrals (27) - 6 - - - (21) Other (1) 18 33 8 283 - (7) 335 Finance income (2)(3) - - - 61 - - 61 $ 3,287 $ 1,675 $ 518 $ 1,688 $ - $ (14) 7,154 Non-Regulated Marketing and trading margin (4) - - - - 143 - 143 Other non-regulated operating revenue - - - 16 16 (10) 22 Mark-to-market (3) - - - - 281 (12) 269 $ - $ - $ - $ 16 $ 440 $ (22) 434 Total operating revenues $ 3,287 $ 1,675 $ 518 $ 1,704 $ 440 $ (36) $ 7,588 (1) Other includes rental revenues, which do not represent revenue from contracts with customers. (2) Revenue related to Brunswick Pipeline's service agreement with Repsol Energy Canada. (3) Revenue which does not represent revenues from contracts with customers. (4) Includes gains (losses) on settlement of energy related derivatives, which do not represent revenue from contracts customers. |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Regulatory Assets and Liabilities [Abstract] | |
Regulatory Assets | As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 |
Regulatory Liabilities | As at December 31 December 31 millions of dollars 2023 2022 Regulatory assets Deferred income tax regulatory assets $ 1,233 $ 1,166 TEC capital cost recovery for early retired assets 671 674 NSPI FAM 395 307 Pension and post-retirement medical plan 364 369 Cost recovery clauses 151 707 Deferrals related to derivative instruments 88 30 Storm cost recovery clauses 52 138 Environmental remediations 26 27 Stranded cost recovery 25 27 NMGC winter event gas cost recovery - 69 Other 100 106 $ 3,105 $ 3,620 Current $ 339 $ 602 Long-term 2,766 3,018 Total regulatory assets $ 3,105 $ 3,620 Regulatory liabilities Accumulated reserve – COR 849 895 Deferred income tax regulatory liabilities 830 877 Cost recovery clauses 32 70 BLPC Self-insurance fund ("SIF") (note 32) 29 30 Deferrals related to derivative instruments 17 230 NMGC gas hedge settlements (note 18) - 162 Other 15 9 $ 1,772 $ 2,273 Current $ 168 $ 495 Long-term 1,604 1,778 Total regulatory liabilities $ 1,772 $ 2,273 |
Investments Subject to Signif_2
Investments Subject to Significant Influence and Equity Income (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Variable Interest Entity [Line Items] | |
Summary of Investments Subject to Significant Influence | Equity Income Percentage Carrying Value For the year ended of As at December 31 December 31 Ownership millions of dollars 2023 2022 2023 2022 2023 LIL (1) $ 747 $ 740 $ 63 $ 58 31.0 NSPML 489 501 46 29 100.0 M&NP 118 128 21 21 12.9 Lucelec (2) 48 49 4 4 19.5 Bear Swamp - - 12 17 50.0 $ 1,402 $ 1,418 $ 146 $ 129 (1) Emera indirectly owns 100 24.5 ownership in LIL is subject to change, based on the balance of capital investments required from Emera and Nalcor Energy complete construction of the LIL. Emera’s ultimate percentage investment in LIL will be determined upon all transmission projects related to the Muskrat Falls development, including the LIL, Labrador Transmission Link Projects, such that Emera’s total investment in the Maritime Link and LIL will equal 49 transmission developments. (2) Emera has significant influence over the operating and financial decisions of these companies through Board representation therefore, records its investment in these entities using the equity method. (3) The investment balance in Bear Swamp is in a credit position primarily as a result of a $ 179 Bear Swamp's credit investment balance of $ 81 95 Consolidated Balance Sheets. |
NSP Maritime Link Inc. [Member] | |
Variable Interest Entity [Line Items] | |
Summary of Investments Subject to Significant Influence | Emera accounts for its variable interest investment in NSPML as an equity investment (note 32). NSPML's consolidated summarized balance sheets are illustrated as follows: As at December 31 millions of dollars 2023 2022 Balance Sheets Current assets $ 21 $ 17 PP&E 1,473 1,517 Regulatory assets 272 265 Non-current assets 29 29 Total assets $ 1,795 $ 1,828 Current liabilities $ 48 $ 48 Long-term debt (1) 1,109 1,149 Non-current liabilities 149 130 Equity 489 501 Total liabilities and equity $ 1,795 $ 1,828 (1) The project debt has been guaranteed by the Government of Canada. |
Other Income, Net (Tables)
Other Income, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Other Income, Net [Abstract] | |
Components of Other Expense, Net | For the Year ended December 31 millions of dollars 2023 2022 Interest income $ 43 $ 25 AFUDC 38 52 Pension non-current service cost recovery 35 24 FX gains (losses) 20 (26) TECO Guatemala Holdings award (1) - 63 Other 22 7 $ 158 $ 145 (1) On December 15, 2022, a payment of $ 63 second and final award issued by the International Centre of the Settlement of Investment Disputes tribunal regarding a dispute an investment in TGH, a wholly-owned subsidiary of TECO Energy. |
Interest Expense, Net (Tables)
Interest Expense, Net (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Interest Expense, Net [Abstract] | |
Components of Interest Expense, Net | Interest expense, net consisted of the following: For the Year ended December 31 millions of Canadian dollars 2023 2022 Interest on debt $ 954 $ 727 Allowance for borrowed funds used during construction (16) (21) Other (13) 3 $ 925 $ 709 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Taxes [Abstract] | |
Reconciliation of Effective Income Tax Rate | The income tax provision, for the years ended December 31, differs from that computed using the enacted combined Canadian federal and provincial statutory income tax rate for the following reasons: millions of dollars 2023 2022 Income before provision for income taxes $ 1,173 $ 1,194 Statutory income tax rate 29.0% 29.0% Income taxes, at statutory income tax rate 340 346 Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities (72) (70) Tax credits (53) (18) Foreign tax rate variance (36) (44) Amortization of deferred income tax regulatory liabilities (33) (33) Tax effect (15) (10) GBPC impairment charge - 21 Other (3) (7) Income tax expense $ 128 $ 185 Effective income tax rate 11% 15% |
Composition of Taxes on Income from Continuing Operations | millions of dollars 2023 2022 Current income taxes $ 26 $ 25 5 8 Deferred income taxes 93 122 128 252 Investment tax credits (29) (7) Operating loss carryforwards (93) (94) (2) (121) Income tax expense $ 128 $ 185 The following table reflects the composition of income before provision for income taxes presented in the Consolidated Statements of Income for the years ended December 31: millions of dollars 2023 2022 Canada $ 171 $ 173 United States 964 1,063 Other 38 (42) Income before provision for income taxes $ 1,173 $ 1,194 |
Schedule of Deferred Income Tax Assets and Liabilities | The deferred income tax assets and liabilities presented in the Consolidated Balance Sheets as at December 31 consisted of the following: millions of dollars 2023 2022 Deferred income tax assets: Tax loss carryforwards $ 1,195 $ 1,207 Tax credit carryforwards 454 415 Derivative instruments 205 45 Regulatory liabilities 175 264 Other 372 341 Total deferred income tax assets before valuation allowance 2,401 2,272 Valuation allowance (363) (312) Total deferred income tax assets after valuation allowance $ 2,038 $ 1,960 Deferred income tax (liabilities): PP&E $ (3,223) $ (2,981) Derivative instruments (235) (125) Investments subject to significant influence (216) (181) Regulatory assets (196) (310) Other (312) (322) Total deferred income tax liabilities $ (4,182) $ (3,919) Consolidated Balance Sheets presentation: Long-term deferred income tax assets $ 208 $ 237 Long-term deferred income tax liabilities (2,352) (2,196) Net deferred income tax liabilities $ (2,144) $ (1,959) |
Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods | Emera’s NOL, capital loss and tax credit carryforwards and their expiration periods as at December 31, 2023 consisted of the following: Subject to Tax Valuation Net Tax Expiration millions of dollars Carryforwards Allowance Carryforwards Period Canada $ 2,914 $ (1,164) $ 1,750 2026 - 2043 73 (73) - Indefinite United States $ 1,360 $ (1) $ 1,359 2036 - Indefinite 1,003 (1) 1,002 2026 - Indefinite 454 (3) 451 2025 - 2043 Other $ 81 $ (28) $ 53 2024 - 2030 |
Details of Change in Unrecognized Tax Benefits | millions of dollars 2023 2022 Balance, January 1 $ 33 $ 28 Increases due to tax positions related to current year 5 5 Increases due to tax positions related to a prior year 1 2 Decreases due to tax positions related to a prior year (2) (2) Balance, December 31 $ 37 $ 33 |
Common Stock (Tables)
Common Stock (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Common Stock [Abstract] | |
Summary of Issued and Outstanding Common Stock | Authorized : 2023 2022 Issued and outstanding: millions of shares dollars millions of shares dollars Balance, January 1 269.95 $ 7,762 261.07 $ 7,242 Issuance of common stock under ATM program (1)(2) 8.29 397 4.07 248 Issued under the DRIP, 5.26 272 4.21 238 Senior management stock options exercised and Employee Share Purchase Plan 0.62 31 0.60 34 Balance, December 31 284.12 $ 8,462 269.95 $ 7,762 (1) For the year ended December 31, 2022, a total of 4,072,469 average price of $ 61.31 250 248 (2) For the year ended December 31, 2023, a total of 8,287,037 average price of $ 48.27 400 397 |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Earnings Per Share [Abstract] | |
Computation of Basic and Diluted Earnings per Share | The following table reconciles the computation of basic and diluted earnings per share: For the Year ended December 31 millions of dollars (except per share amounts) 2023 2022 Numerator Net income attributable to common shareholders $ 977.7 $ 945.1 Diluted numerator 977.7 945.1 Denominator Weighted average shares of common stock outstanding – basic 273.6 265.5 Stock-based compensation 0.2 0.4 Weighted average shares of common stock outstanding – diluted 273.8 265.9 Earnings per common share Basic $ 3.57 $ 3.56 Diluted $ 3.57 $ 3.55 |
Accumulated Other Comprehensi_2
Accumulated Other Comprehensive Income (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accumulated Other Comprehensive Income [Abstract] | |
Components of Accumulated Other Comprehensive Income | The components of AOCI are as follows: millions of dollars Unrealized (loss) gain on translation of self-sustaining foreign operations Net change in net investment hedges Losses on derivatives recognized as cash flow hedges Net change on available- for-sale investments Net change in unrecognized pension and post-retirement benefit costs Total AOCI For the year ended December 31, 2023 Balance, January 1, 2023 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 Other comprehensive (loss) income before reclassifications (270) 38 - - (232) Amounts reclassified from AOCI - - (2) - (39) (41) Net current period other comprehensive (loss) income (270) 38 (2) - (39) (273) Balance, December 31, 2023 $ 369 $ (24) $ 14 $ (2) $ (52) $ 305 For the year ended December 31, 2022 Balance, January 1, 2022 $ 10 $ 35 $ 18 $ (1) $ (37) $ 25 Other comprehensive income (loss) before reclassifications 629 (97) - (1) - 531 Amounts reclassified from AOCI - - (2) - 24 22 Net current period other comprehensive income (loss) 629 (97) (2) (1) 24 553 Balance, December 31, 2022 $ 639 $ (62) $ 16 $ (2) $ (13) $ 578 |
Reclassifications out of Accumulated Other Comprehensive Income (Loss) | The reclassifications out of AOCI are as follows: For the Year ended December 31 millions of dollars 2023 2022 Affected line item in the Consolidated Financial Statements Gains on derivatives recognized as cash flow hedges Interest expense, net $ (2) $ (2) Net change in unrecognized pension and post-retirement benefit costs Other income, net $ - $ 10 Other income, net 2 - Pension and post-retirement benefits (40) 15 Total before tax (38) 25 Income tax expense (1) (1) Total net of tax $ (39) $ 24 Total reclassifications out of AOCI, net of tax, for the period $ (41) $ 22 |
Inventory (Tables)
Inventory (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Inventory [Abstract] | |
Components of Inventory | As at December 31 December 31 millions of dollars 2023 2022 Fuel $ 382 $ 404 Materials 408 365 Total $ 790 $ 769 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments | |
Derivative Assets and Liabilities | Derivative assets and liabilities relating to the foregoing categories consisted of the following: Derivative Assets Derivative Liabilities As at December 31 December 31 December 31 December 31 millions of dollars 2023 2022 2023 2022 Regulatory deferral: $ 16 $ 186 $ 76 $ 42 3 18 3 1 - 52 - - 19 256 79 43 HFT derivatives: 29 89 36 77 319 340 531 1,224 348 429 567 1,301 Other derivatives: 4 - - 5 18 5 7 23 22 5 7 28 Total gross current derivatives 389 690 653 1,372 Impact of master netting agreements: (3) (18) (3) (18) (146) (276) (146) (276) Total impact of master netting agreements (149) (294) (149) (294) Total derivatives $ 240 $ 396 $ 504 $ 1,078 Current (1) 174 296 386 888 Long-term (1) 66 100 118 190 Total derivatives $ 240 $ 396 $ 504 $ 1,078 (1) Derivative assets and liabilities are classified as current or long-term based upon the maturities of the underlying |
Cash Flow Hedges Recorded in AOCI | For the Year ended December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Realized gain in interest expense, net $ 2 $ 2 Total gains in net income $ 2 $ 2 As at December 31 December 31 millions of dollars 2023 2022 Interest Interest rate hedge rate hedge Total unrealized gain in AOCI – effective portion, net of tax $ 14 $ 16 |
Changes in Realized and Unrealized Gains (Losses) on Derivatives | Physical Commodity Physical Commodity natural gas swaps and FX natural gas swaps and FX millions of dollars purchases forwards forwards purchases forwards forwards For the year ended December 31 2023 2022 Unrealized gain (loss) in regulatory assets $ - $ (109) $ (3) $ - $ (69) $ 1 Unrealized gain (loss) in regulatory liabilities (3) (73) - 28 343 16 Realized (gain) loss in regulatory assets - (5) - - 48 - Realized (gain) loss in regulatory liabilities - 2 - - (41) - Realized (gain) loss in inventory (1) - 4 (10) - (121) 1 Realized (gain) in regulated fuel for generation and purchased power (2) (49) (9) (4) (64) (146) - Other - (14) - - - - Total change in derivative instruments $ (52) $ (204) $ (17) $ (36) $ 14 $ 18 (1) Realized (gains) losses will be recognized in fuel for generation and purchased power when the hedged item is consumed. (2) Realized (gains) losses on derivative instruments settled and consumed in the period and hedging relationships that have been terminated or the hedged transaction is no longer probable. For the Year ended December 31 millions of dollars 2023 2022 Power swaps and physical contracts in non-regulated operating revenues $ (6) $ 17 Natural gas swaps, forwards, futures and physical contracts in non-regulated operating revenues 1,043 47 Total gains in net income $ 1,037 $ 64 For the Year ended December 31 millions of dollars 2023 2022 FX Equity FX Equity Forwards Derivatives Forwards Derivatives Unrealized gain (loss) in OM&G $ - $ 4 $ - $ (5) Unrealized gain (loss) in other income, net 28 - (18) - Realized loss in OM&G - (13) - (17) Realized loss in other income, net (11) - (6) - Total gains (losses) in net income $ 17 $ (9) $ (24) $ (22) |
Notional Volumes of Outstanding Derivatives | millions 2024 2025-2026 Physical natural gas purchases: Natural gas (MMBtu) 7 6 Commodity swaps and forwards purchases: Natural gas (MMBtu) 16 10 Power (MWh) 1 1 Coal (metric tonnes) 1 - FX swaps and forwards: FX contracts (millions of USD) $ 241 $ 70 Weighted average rate 1.3155 1.3197 % of USD requirements 63% 17% 2028 and millions 2024 2025 2026 2027 thereafter Natural gas purchases (Mmbtu) 296 80 50 38 30 Natural gas sales (Mmbtu) 338 86 16 6 4 Power purchases (MWh) 1 - - - - Power sales (MWh) 1 - - - - |
Summary of Concentration Risk | Concentration Risk The Company's concentrations of risk consisted of the following: As at December 31, 2023 December 31, 2022 millions of dollars % of total exposure millions of dollars % of total exposure Receivables, net Regulated utilities: Residential $ 476 31% $ 455 19% Commercial 194 13% 192 8% Industrial 84 5% 121 5% Other 103 7% 122 5% Cash collateral 94 6% - 0% 951 62% 890 37% Trading group: Credit rating of A- or above 47 3% 125 5% Credit rating of BBB- to BBB+ 33 2% 75 3% Not rated 108 7% 307 13% 188 12% 507 21% Other accounts receivable 151 10% 585 25% 1,290 84% 1,982 83% Derivative Instruments (current and long-term) Credit rating of A- or above 138 9% 202 9% Credit rating of BBB- to BBB+ 7 1% 8 0% Not rated 95 6% 186 8% 240 16% 396 17% $ 1,530 100% $ 2,378 100% |
Cash Collateral Positions | As at December 31 December 31 millions of dollars 2023 2022 Cash collateral provided to others $ 101 $ 224 Cash collateral received from others $ 22 $ 112 |
FV Measurements (Tables)
FV Measurements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
FV Measurements [Abstract] | |
Classification of Fair Value of Derivatives | As at December 31, 2023 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 7 $ 6 $ - $ 13 - 3 - 3 7 9 - 16 HFT derivatives: (5) 23 - 18 42 108 34 184 37 131 34 202 Other derivatives: - 18 - 18 4 - - 4 4 18 - 22 Total assets 48 158 34 240 Liabilities Regulatory deferral: 43 30 - 73 - 3 - 3 43 33 - 76 HFT derivatives: - 24 - 24 13 19 365 397 13 43 365 421 Other derivatives: - 7 - 7 - 7 - 7 Total liabilities 56 83 365 504 Net assets (liabilities) $ (8) $ 75 $ (331) $ (264) As at December 31, 2022 millions of dollars Level 1 Level 2 Level 3 Total Assets Regulatory deferral: $ 120 $ 48 $ - $ 168 - 18 - 18 - - 52 52 120 66 52 238 HFT derivatives: 9 31 4 44 3 72 34 109 12 103 38 153 Other derivatives: - 5 - 5 Total assets 132 174 90 396 Liabilities Regulatory deferral: 15 9 - 24 - 1 - 1 15 10 - 25 HFT derivatives: 2 28 1 31 51 118 825 994 53 146 826 1,025 Other derivatives: - 23 - 23 5 - - 5 Total liabilities 73 179 826 1,078 Net assets (liabilities) $ 59 $ (5) $ (736) $ (682) |
Change in Fair Value of Level 3 Financial Assets | The change in the FV of the Level 3 financial assets for the year ended December 31, 2023 was as follows: Regulatory Deferral HFT Derivatives Physical natural Natural millions of dollars gas purchases Power gas Total Balance, January 1, 2023 $ 52 $ 4 $ 34 $ 90 Realized gains (losses) included in fuel for generation and purchased power (49) - - (49) Unrealized gains (losses) included in regulatory assets and liabilities (3) - - (3) Total realized and unrealized gains (losses) included in non-regulated operating revenues - (4) - (4) Balance, December 31, 2023 $ - $ - $ 34 $ 34 |
Change in Fair Value of Level 3 Financial Liabilities | The change in the FV of the Level 3 financial liabilities for the year ended December 31, 2023 was as follows: Natural millions of dollars Power gas Total Balance, January 1, 2023 $ 1 $ 825 $ 826 Total realized and unrealized gains included in non- regulated operating revenues (1) (460) (461) Balance, December 31, 2023 $ - $ 365 $ 365 |
Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements | Significant Weighted millions of dollars FV Unobservable Input Low High average (1) Assets Liabilities As at December 31, 2023 HFT derivatives – Natural 34 365 Third-party pricing $1.27 $16.25 $4.85 gas swaps, futures, forwards and physical contracts Total $ 34 $ 365 Net liability $ 331 As at December 31, 2022 Regulatory deferral – Physical $ 52 $ - Third-party pricing $5.79 $31.85 $12.27 natural gas purchases HFT derivatives – Power 4 1 Third-party pricing $43.24 $269.10 $138.79 swaps and physical contracts HFT derivatives – Natural 34 825 Third-party pricing $2.45 $33.88 $12.01 gas swaps, futures, forwards and physical contracts Total $ 90 $ 826 Net liability $ 736 (1) Unobservable inputs were weighted by the relative FV of the instruments. |
Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets | Long-term debt is a financial liability not measured at FV on the Consolidated Balance Sheets. The balance consisted of the following: As at Carrying millions of dollars Amount FV Level 1 Level 2 Level 3 Total December 31, 2023 $ 18,365 $ 16,621 $ - $ 16,363 $ 258 $ 16,621 December 31, 2022 $ 16,318 $ 14,670 $ - $ 14,284 $ 386 $ 14,670 |
Receivables and Other Current_2
Receivables and Other Current Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Receivables and Other Current Assets [Abstract] | |
Summary of Receivables and Other Current Assets | 18. As at December 31 December 31 millions of dollars 2023 2022 Customer accounts receivable – billed $ 805 $ 1,096 Capitalized transportation capacity (1) 358 781 Customer accounts receivable – unbilled 363 424 Prepaid expenses 105 82 Income tax receivable 10 9 Allowance for credit losses (15) (17) NMGC gas hedge settlement receivable 162 Other 191 360 Total receivables and other current assets $ 1,817 $ 2,897 (1) Capitalized transportation capacity represents the value of transportation/storage received by EES on asset management agreements at the inception of the contracts. The asset is amortized over the term of each contract. (2) Offsetting amount is included in regulatory liabilities for NMGC as gas hedges are part of the PGAC. For more information, to note 6. |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Lessee, Operating Leases and Additional Information | As at December 31 December 31 millions of dollars Classification 2023 2022 Right-of-use asset Other long-term assets $ 54 $ 58 Lease liabilities Other current liabilities 3 3 Other long-term liabilities 55 59 Total lease liabilities $ 58 $ 62 Additional information related to Emera's leases is as follows: Year ended December 31 For the 2023 2022 Cash paid for amounts included in the measurement of lease liabilities: $ 8 $ 8 Right-of-use assets obtained in exchange for lease obligations: $ 1 $ 1 Weighted average remaining lease term (years) 44 44 Weighted average discount rate- operating leases 3.93% 3.98% |
Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases | Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter are as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments $ 6 $ 5 $ 3 $ 3 $ 3 $ 111 $ 131 Less imputed interest (73) Total $ 58 |
Lessor, Direct Finance and Sales-Type Leases | As at December 31 December 31 millions of dollars 2023 2022 Total minimum lease payment to be received $ 1,360 $ 1,393 Less: amounts representing estimated executory costs (190) (205) Minimum lease payments receivable $ 1,170 $ 1,188 Estimated residual value of leased property (unguaranteed) 183 183 Less: Credit loss reserve (2) - Less: unearned finance lease income (693) (733) Net investment in direct finance and sales-type leases $ 658 $ 638 Principal due within one year (included in "Receivables and other current assets") 37 34 Net Investment in direct finance and sales type leases - long-term $ 621 $ 604 |
Lessor, Future Minimum Lease Payments to be Received | As at December 31, 2023, future minimum lease payments to be received for each of the next five years and in aggregate thereafter were as follows: millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Minimum lease payments to be received $ 97 $ 99 $ 98 $ 97 $ 96 $ 873 $ 1,360 Less: executory costs (190) Total $ 1,170 |
Property, Plant and Equipment (
Property, Plant and Equipment (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Regulated and Non-Regulated Assets | PP&E consisted of the following regulated and non-regulated assets: As at December 31 December 31 millions of dollars Estimated useful life 2023 2022 Generation 3 131 $ 13,500 $ 13,083 Transmission 10 80 2,835 2,731 Distribution 4 80 7,417 6,978 Gas transmission and distribution 6 92 5,536 5,061 General plant and other 2 71 2,985 2,723 Total cost 32,273 30,576 Less: Accumulated depreciation (1) (9,994) (9,574) 22,279 21,002 Construction work in progress (1) 2,097 1,994 Net book value $ 24,376 $ 22,996 (1) SeaCoast owns a 50 % undivided ownership interest in a jointly owned 26 -mile pipeline lateral located in Florida, which went into service in 2020. At December 31, 2023, SeaCoast’s share of plant in service was $ 27 27 accumulated depreciation of $ 2 1 funds and all operations are accounted for as if such participating interest were a wholly owned facility. expenses of the jointly owned pipeline is included in "OM&G" in the Consolidated Statements of Income. |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Employee Benefit Plans [Abstract] | |
Changes in Benefit Obligation and Plan Assets and Funded Status | For the Year ended December 31 millions of dollars 2023 2022 Change in Projected Benefit Obligation ("PBO") and Accumulated Post- retirement Benefit Obligation ("APBO") Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Balance, January 1 $ 2,158 $ 243 $ 2,624 $ 318 Service cost 30 3 41 4 Plan participant contributions 6 6 6 6 Interest cost 111 13 80 9 Plan amendments - (14) - - Benefits paid (147) (29) (174) (31) Actuarial losses (gains) 146 10 (480) (79) Settlements and curtailments (8) - (6) - FX translation adjustment (23) (5) 67 16 Balance, December 31 $ 2,273 $ 227 $ 2,158 $ 243 Change in plan assets Balance, January 1 $ 2,163 $ 46 $ 2,702 $ 51 Employer contributions 42 23 45 24 Plan participant contributions 6 6 6 6 Benefits paid (147) (29) (174) (31) Actual return on assets, net of expenses 262 3 (489) (7) Settlements and curtailments (8) - (6) - FX translation adjustment (20) (1) 79 3 Balance, December 31 $ 2,298 $ 48 $ 2,163 $ 46 Funded status, end of year $ 25 $ (179) $ 5 $ (197) |
Plans with PBO/APBO in Excess of Plan Assets and Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans PBO/APBO $ 120 $ 205 $ 1,006 $ 221 FV of plan assets 37 - 914 - Funded status $ (83) $ (205) $ (92) $ (221) millions of dollars 2023 2022 Defined benefit pension plans Defined benefit pension plans ABO $ 114 $ 111 FV of plan assets 37 33 Funded status $ (77) $ (78) |
Amounts Recognized in Consolidated Balance Sheets | As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Other current liabilities $ (5) $ (18) $ (13) $ (20) Long-term liabilities (78) (187) (80) (201) Other long-term assets 108 26 98 24 AOCI, net of tax and regulatory assets 385 20 358 22 Less: Deferred income tax (expense) recovery in AOCI (8) (1) (7) (1) Net amount recognized $ 402 $ (160) $ 356 $ (176) |
Amounts Recognized in AOCI and Regulatory Assets | Regulatory assets Actuarial (gains) losses Past service (gains) costs millions of dollars Defined Benefit Pension Plans Balance, January 1, 2023 $ 336 $ 15 $ - Amortized in current period (6) (3) - Current year additions 1 41 - Change in FX rate (7) - - Balance, December 31, 2023 $ 324 $ 53 $ - Non-pension benefits plans Balance, January 1, 2023 $ 31 $ (10) $ - Amortized in current period 2 3 - Current year reductions (3) (1) (3) Change in FX rate (1) - 1 Balance, December 31, 2023 $ 29 $ (8) $ (2) As at December 31 December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Actuarial losses (gains) $ 53 (8) $ 15 $ (10) Past service gains - (2) - - Deferred income tax expense 8 1 7 1 AOCI, net of tax 61 (9) 22 (9) Regulatory assets 324 29 336 31 AOCI, net of tax and regulatory assets $ 385 $ 20 $ 358 $ 22 |
Net Periodic Benefit Cost | As at Year ended December 31 millions of dollars 2023 2022 Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Service cost $ 30 $ 3 $ 41 $ 4 Interest cost 111 13 80 9 Expected return on plan assets (161) (2) (144) - Current year amortization of: 1 (3) 8 - 6 (2) 21 2 Settlement, curtailments 2 - 2 - Total $ (11) $ 9 $ 8 $ 15 |
Pension Plan Asset Allocations | Canadian Pension Plans Asset Class Target Range at Market Short-term securities 0% to 10% Fixed income 34% to 49% Equities: 7% to 17% 35% to 59% Non-Canadian Pension Plans Asset Class Target Range at Market Weighted average Cash and cash equivalents 0% to 10% Fixed income 29% to 49% Equities 48% to 68% |
Fair Value of Plan Assets | millions of dollars NAV Level 1 Level 2 Total Percentage As at December 31, 2023 Cash and cash equivalents $ - $ 40 $ - $ 40 2 % Net in-transits - (9) - (9) - % Equity securities: - 96 - 96 4 % - 141 - 141 6 % - 112 - 112 5 % Fixed income securities: - - 172 172 8 % - - 90 90 4 % - 4 5 9 - % Mutual funds - 50 - 50 2 % Other - 6 (1) 5 - % Open-ended investments measured at NAV 1,006 - - 1,006 44 % Common collective trusts measured at NAV (2) 586 - - 586 25 % Total $ 1,592 $ 440 $ 266 $ 2,298 100 % As at December 31, 2022 Cash and cash equivalents $ - $ 70 $ - $ 70 3 % Net in-transits - (70) - (70) (3) % Equity securities: - 87 - 87 4 % - 233 - 233 11 % - 186 - 186 8 % Fixed income securities: - - 104 104 5 % - - 83 83 4 % - 3 11 14 1 % Mutual funds - 68 - 68 3 % Other - - (3) (3) - % Open-ended investments measured at NAV 790 - - 790 36 % Common collective trusts measured at NAV (2) 601 - - 601 28 % Total $ 1,391 $ 577 $ 195 $ 2,163 100 % (1) Net asset value ("NAV") investments are open-ended or pooled funds. NAV’s are calculated (2) The common collective trusts are private funds valued at NAV. securities. Since the prices are not published to external sources, NAV primarily in equity securities of domestic and foreign issuers while others invest in long duration U.S. investment grade fixed income assets and seeks to increase return through active management of interest rate and credit risks. The funds honour subscription and redemption activity regularly. |
Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans | millions of dollars Defined benefit pension plans Non-pension benefit plans Expected employer contributions 2024 $ 34 $ 19 Expected benefit payments 2024 172 21 2025 163 21 2026 166 21 2027 171 21 2028 173 20 2029 – 2033 890 95 |
Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans | Assumptions: The following table shows the assumptions that have been used in accounting for DB pension and other post-retirement benefit plans: 2023 2022 (weighted average assumptions) Defined benefit pension plans Non-pension benefit plans Defined benefit pension plans Non-pension benefit plans Benefit obligation – December 31: Discount rate - past service 4.89 % 4.89 % 5.33 % 5.31 % Discount rate - future service 4.88 % 4.89 % 5.34 % 5.32 % Rate of compensation increase 3.87 % 3.85 % 3.62 % 3.61 % Health care trend - 6.04 % - 5.40 % - 3.76 % - 3.77 % 2043 2043 Benefit cost for year ended December 31: Discount rate - past service 5.33 % 5.31 % 3.05 % 2.81 % Discount rate - future service 5.34 % 5.32 % 3.18 % 2.92 % Expected long-term return on plan assets 6.56 % 2.16 % 6.07 % 1.32 % Rate of compensation increase 3.62 % 3.61 % 3.31 % 3.29 % Health care trend - 5.40 % - 5.09 % - 3.77 % - 3.77 % 2043 2042 Actual assumptions used differ by plan. |
Goodwill (Tables)
Goodwill (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Goodwill [Abstract] | |
Change in Goodwill | 22. The change in goodwill for the year ended December 31 was due to the following: millions of dollars 2023 2022 Balance, January 1 $ 6,012 $ 5,696 Change in FX rate (141) 389 GBPC impairment charge - (73) Balance, December 31 $ 5,871 $ 6,012 |
Short-Term Debt (Tables)
Short-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Short-Term Debt [Abstract] | |
Short-Term Debt and Related Weighted-Average Interest Rates | millions of dollars 2023 Weighted average interest rate 2022 Weighted average interest rate TEC Advances on revolving credit facilities $ 277 5.68 % $ 1,380 5.00 % Emera Non-revolving term facilities 796 6.07 % 796 5.19 % Bank indebtedness 9 - % - - % TECO Finance Advances on revolving credit and term facilities 245 6.54 % 481 5.47 % PGS Advances on revolving credit facilities 73 6.36 % - - % NMGC Advances on revolving credit facilities 25 6.46 % 59 5.15 % GBPC Advances on revolving credit facilities 8 5.54 % 10 5.25 % Short-term debt $ 1,433 $ 2,726 The Company’s total short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 TEC - Unsecured committed revolving credit facility 2026 $ 401 $ 1,084 TECO Energy/TECO Finance - revolving credit facility 2026 - 542 TECO Finance - Unsecured committed revolving credit facility 2026 529 - Emera - Unsecured non-revolving term facility 2024 400 400 Emera - Unsecured non-revolving term facility 2024 400 400 PGS - Unsecured revolving credit facility 2028 331 - TEC - Unsecured revolving facility 2024 265 542 TEC - Unsecured revolving facility 2024 265 - NMGC - Unsecured revolving credit facility 2026 165 169 Other - Unsecured committed revolving credit facilities Various 17 18 Total $ 2,773 $ 3,155 Less: Advances under revolving credit and term facilities 1,433 2,731 Letters of credit issued within the credit facilities 3 4 Total advances under available facilities 1,436 2,735 Available capacity under existing agreements $ 1,337 $ 420 |
Other Current Liabilities (Tabl
Other Current Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Other Current Liabilities | |
Components of Other Current Liabilities | As at December 31 December 31 millions of dollars 2023 2022 Accrued charges $ 172 $ 174 Nova Scotia Cap-and-Trade Program provision (note 6) - 172 Accrued interest on long-term debt 107 97 Pension and post-retirement liabilities (note 21) 23 33 Sales and other taxes payable 11 14 Income tax payable 2 9 Other 112 80 $ 427 $ 579 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Long-term Debt [Abstract] | |
Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity | Weighted average interest rate (1) millions of dollars 2023 2022 Maturity 2023 2022 Emera Bankers acceptances, SOFR loans Variable Variable 2027 $ 465 $ 403 Unsecured fixed rate notes 4.84% 2.90% 2030 500 500 Fixed to floating subordinated notes (2) 6.75% 6.75% 2076 1,587 1,625 $ 2,552 $ 2,528 Emera Finance Unsecured senior notes 3.65% 3.65% 2024 - 2046 $ 3,637 $ 3,725 TEC (3) Fixed rate notes and bonds 4.61% 4.15% 2024 - 2051 $ 5,654 $ 4,341 PGS Fixed rate notes and bonds 5.63% 3.78% 2028 - 2053 $ 1,223 $ 772 NMGC Fixed rate notes and bonds 3.78% 3.11% 2026 - 2051 $ 642 $ 521 Non-revolving term facility, floating rate Variable Variable 2024 30 108 $ 672 $ 629 NMGI Fixed rate notes and bonds 3.64% 3.64% 2024 $ 198 $ 203 NSPI Discount Notes (4) Variable Variable 2024 - 2027 $ 721 $ 881 Medium term fixed rate notes 5.13% 5.14% 2025 - 2097 3,165 2,665 $ 3,886 $ 3,546 EBP Senior secured credit facility Variable Variable 2026 $ 246 $ 249 ECI Secured senior notes Variable Variable 2027 $ 75 $ 86 Amortizing fixed rate notes 4.00% 3.97% 2026 79 100 Non-revolving term facility, floating rate Variable Variable 2025 29 30 Non-revolving term facility, fixed rate 2.15% 2.05% 2025 - 2027 155 91 Secured fixed rate senior notes (5) 3.09% 3.06% 2024 - 2029 84 142 $ 422 $ 449 Adjustments Fair market value adjustment - TECO Energy acquisition $ - $ 2 Debt issuance costs (125) (126) Amount due within one year (676) (574) $ (801) $ (698) Long-Term Debt $ 17,689 $ 15,744 (1) Weighted average interest rate of fixed rate long-term debt. (2) In 2023, the Company recognized $ 109 110 subordinated notes. (3) A substantial part of TEC’s tangible assets are pledged as collateral to secure its first mortgage bonds. There are currently bonds outstanding under TEC’s first mortgage bond indenture. (4) Discount notes are backed by a revolving credit facility which matures in 2027. Banker’s acceptances are issued under NSPI’s non-revolving term facility which matures in 2024. NSPI has the intention and unencumbered ability to refinance bankers’ acceptances for a period of greater than one year. (5) Notes are issued and payable in either USD or BBD. The Company’s total long-term revolving credit facilities, outstanding borrowings and available capacity as at December 31 were as follows: millions of dollars Maturity 2023 2022 Emera – revolving credit facility (1) June 2027 $ 900 $ 900 TEC - Unsecured committed revolving credit facility December 2026 657 - NSPI - revolving credit facility (1) December 2027 800 800 NSPI - non-revolving credit facility July 2024 400 400 Emera - Unsecured non-revolving credit facility February 2024 400 - NMGC - Unsecured non-revolving credit facility March 2024 30 108 ECI – revolving credit facilities October 2024 10 11 Total $ 3,197 $ 2,219 Less: Borrowings under credit facilities 1,884 1,396 Letters of credit issued inside credit facilities 6 12 Use of available facilities $ 1,890 $ 1,408 Available capacity under existing agreements $ 1,307 $ 811 (1) Advances on the revolving credit facility can be made by way of overdraft on accounts up to $ 50 As at Financial Covenant Requirement December 31, 2023 Emera Syndicated credit facilities Debt to capital ratio Less than or equal to 0.70 0.57 |
Long-Term Debt Maturities | millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Emera $ 199 $ - $ 1,587 $ 266 $ - $ 500 $ 2,552 Emera US Finance LP 397 - 992 - - 2,248 3,637 TEC 397 - - - - 5,257 5,654 PGS - - - - 463 760 1,223 NMGC 30 - 93 - - 549 672 NMGI 198 - - - - - 198 NSPI 398 125 40 323 - 3,000 3,886 EBP - - 246 - - - 246 ECI 51 139 89 77 62 4 422 Total $ 1,670 $ 264 $ 3,047 $ 666 $ 525 $ 12,318 $ 18,490 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Asset Retirement Obligations [Abstract] | |
Change in Asset Retirement Obligations | The change in ARO for the years ended December 31 is as follows: millions of dollars 2023 2022 Balance, January 1 $ 174 $ 174 Accretion included in depreciation expense 9 9 Change in FX rate (1) 3 Additions - 1 Accretion deferred to regulatory asset (included in PP&E) 18 1 Liabilities settled (8) (1) Revisions in estimated cash flows - (13) Balance, December 31 $ 192 $ 174 |
Commitments and Contingencies (
Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Summary of Contractual Commitments | millions of dollars 2024 2025 2026 2027 2028 Thereafter Total Transportation (1) $ 696 $ 495 $ 405 $ 388 $ 338 $ 2,597 $ 4,919 Purchased power (2) 274 249 263 312 312 3,435 4,845 Fuel, gas supply and storage 556 215 62 - 5 - 838 Capital projects 778 111 70 1 - - 960 Equity investment commitments (3) 240 - - - - - 240 Other 154 147 56 46 35 221 659 $ 2,698 $ 1,217 $ 856 $ 747 $ 690 $ 6,253 $ 12,461 (1) Purchasing commitments for transportation of fuel and transportation capacity on various pipelines. $ 134 (2) Annual requirement to purchase electricity production from IPPs or other utilities over varying contract lengths. (3) Emera has a commitment to make equity contributions to the LIL related to an investment true up in 2024 and sustaining contributions over the life of the partnership. respective investment obligations of the parties in relation the Maritime Link and LIL which is expected to be approximately 240 million in 2024. In addition, Emera has future commitments to provide sustaining capital to the LIL for routine capital and major maintenance. |
Cumulative Preferred Stock (Tab
Cumulative Preferred Stock (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Cumulative Preferred Stock [Abstract] | |
Summary of Cumulative Preferred Stock | Authorized: Unlimited number of First Preferred shares, issuable in series. Unlimited number of Second Preferred shares, issuable in series. December 31, 2023 December 31, 2022 Annual Dividend Redemption Issued and Net Issued and Net Per Share Price per share Outstanding Proceeds Outstanding Proceeds Series A $ 0.5456 $ 25.00 4,866,814 $ 119 4,866,814 $ 119 Series B Floating $ 25.00 1,133,186 $ 28 1,133,186 $ 28 Series C $ 1.6085 $ 25.00 10,000,000 $ 245 10,000,000 $ 245 Series E $ 1.1250 $ 25.00 5,000,000 $ 122 5,000,000 $ 122 Series F $ 1.0505 $ 25.00 8,000,000 $ 195 8,000,000 $ 195 Series H $ 1.5810 $ 25.00 12,000,000 $ 295 12,000,000 $ 295 Series J $ 1.0625 $ 25.00 8,000,000 $ 196 8,000,000 $ 196 Series L $ 1.1500 $ 26.00 9,000,000 $ 222 9,000,000 $ 222 Total 58,000,000 $ 1,422 58,000,000 $ 1,422 Characteristics of the First Preferred Shares: First Preferred Shares (1)(2) Initial Yield (%) Current Annual Dividend ($) Minimum Reset Dividend Yield (%) Earliest Redemption and/or Conversion Option Date Redemption Value ($) Right to Convert on a one for one basis Fixed rate reset (3)(4) 4.400 0.5456 1.84 August 15, 2025 25.00 Series B 4.100 1.6085 2.65 August 15, 2028 25.00 Series D 4.202 1.0505 2.63 February 15, 2025 25.00 Series G Minimum rate reset (3)(4) 2.393 Floating 1.84 August 15, 2025 25.00 Series A (5)(7) 4.900 1.5810 4.90 August 15, 2028 25.00 Series I 4.250 1.0625 4.25 May 15, 2026 25.00 Series K Perpetual fixed rate 4.500 1.1250 25.00 (9) 4.600 1.1500 November 15, 2026 26.00 (1) Holders are entitled to receive fixed or floating cumulative cash dividends when declared by the Board of Directors of the Corporation. (2) On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding First Shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but dates fixed for redemption. (3) On the redemption and/or conversion option date the reset annual dividend per share will be determined by multiplying 25.00 share by the annual fixed or floating dividend rate, which for Series A, C, F and H is the sum of the five-year Government Bond Yield on the applicable reset date, plus the applicable reset dividend yield 4.90 (4) On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their into an equal number of Cumulative Redeemable First Preferred Shares of a specified series. The Company has the right the outstanding Preferred Shares, Series D, Series G and Series I shares without the consent of the holder every five years for cash, in whole or in part at a price of $ 25.00 redemption and $ 25.50 of redemptions on any other date after August 15, 2028, February 15, 2025 and August 15, 2028, respectively. yield for Series I equals the Government of Treasury Bill Rate on the applicable reset date, plus 2.54 (5) On July 6, 2023, Emera announced it would not redeem the outstanding Preferred Shares, Series C and Series 2023. On August 4, 2023, Emera announced after having taken into account all conversion notices received from holders, C Shares were converted into Series D Shares and no Series H Shares were converted into Series I shares. (6) The annual fixed dividend per share for Series C Shares was reset from $ 1.1802 1.6085 including August 15, 2028. (7) The annual fixed dividend per share for Series H Shares was reset from $ 1.2250 1.5810 including August 15, 2028. (8) First Preferred Shares, Series E are redeemable at $25.00 per share. (9) First Preferred Shares, Series L are redeemable at $ 26.00 $ 0.25 25.00 |
Non-Controlling Interest in S_2
Non-Controlling Interest in Subsidiaries (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Non-Controlling Interest in Subsidiaries [Abstract] | |
Components of Non-Controlling Interest | 29. As at December 31 December 31 millions of dollars 2023 2022 Preferred shares of GBPC $ 14 $ 14 $ 14 $ 14 |
Preferred Shares of GBPC | Preferred shares of GBPC: Authorized: 10,000 2023 2022 Issued and outstanding: number of shares millions of dollars number of shares millions of dollars Outstanding as at December 31 10,000 $ 14 10,000 $ 14 |
Supplementary Information to _2
Supplementary Information to Consolidated Statements of Cash Flows (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Supplementary Information to Consolidated Statements of Cash Flows [Abstract] | |
Summary of Supplementary Information to Consolidated Statement of Cash Flows | For the Year ended December 31 millions of dollars 2023 2022 Changes in non-cash working capital: $ (31) $ (214) (1) 653 (636) (538) 423 (2) (179) 193 Total non-cash working capital $ (95) $ (234) (1) Includes $ 162 162 ) million). Offsetting regulatory liability is included in operating cash flow before working capital resulting in no impact to net cash provided by operating activities. (2) Includes ($ 166 ) million related to the Nova Scotia Cap-and-Trade program (2022 – $ 172 6. Offsetting regulatory asset (FAM) balance is cash provided by operating activities. For the Year ended December 31 millions of dollars 2023 2022 Supplemental disclosure of cash paid: Interest $ 930 $ 699 Income taxes $ 43 $ 67 Supplemental disclosure of non-cash activities: Common share dividends reinvested $ 271 $ 237 Decrease in accrued capital expenditures $ (19) $ (13) Reclassification of short-term debt to long-term debt $ 657 $ - Reclassification of long-term debt to short-term debt $ - $ 500 Supplemental disclosure of operating activities: Net change in short-term regulatory assets and liabilities $ 123 $ (157) |
Stock Based Compensation (Table
Stock Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Stock-Based Compensation [Abstract] | |
Weighted Average Fair Values per Stock Option and Assumptions for Options Granted | 2023 2022 Weighted average FV per option $ 6.32 $ 5.35 Expected term (1) 5 5 Risk-free interest rate (2) 3.53 % 1.79 % Expected dividend yield (3) 5.05 % 4.55 % Expected volatility (4) 20.07 % 18.87 % (1) The expected term of the option awards is calculated based on historical exercise behaviour and represents the period that the options are expected to be outstanding. (2) Based on the Bank of Canada five-year government bond yields. (3) Incorporates current dividend rates and historical dividend increase patterns. (4) Estimated using the five-year historical volatility. |
Summary of Stock Option Information | Total Options Non-Vested Options (1) Number of Options average exercise price per share Number of Options Weighted average grant date fair-value Outstanding as at December 31, 2022 2,853,879 $ 50.41 1,348,400 $ 4.08 Granted 483,100 54.64 483,100 6.32 Exercised (146,475) 43.94 N/A N/A Forfeited (94,900) 56.32 (51,625) 3.61 Vested N/A N/A (526,620) 3.58 Options outstanding December 31, 2023 3,095,604 $ 51.20 1,253,255 $ 5.17 Options exercisable December 31, 2023 (2)(3) 1,842,349 $ 48.39 (1) As at December 31, 2023, there was $ 5 expected to be recognized over a weighted average period of approximately 3 4 3 (2) As at December 31, 2023, the weighted average remaining term of vested options was 5 $ 8 5 10 (3) As at December 31, 2023, the FV of options that vested in the year was $ 2 2 |
Summary of Activity Related to Employee and Director Deferred Share Units | Employee DSU Weighted Average Grant Date FV Director DSU Weighted Average Grant Date FV Outstanding as at December 31, 2022 627,223 $ 41.55 664,258 $ 45.83 Granted including DRIP 85,740 47.66 117,893 49.99 Exercised N/A N/A (53,093) 49.39 Outstanding and exercisable as at December 31, 2023 712,963 $ 42.29 729,058 $ 46.24 |
Summary of Activity Related to Employee Performance Share Units | Employee PSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 690,446 $ 56.24 $ 40 Granted including DRIP 386,261 52.71 Exercised (323,155) 54.62 Forfeited (10,187) 55.15 Outstanding as at December 31, 2023 743,365 $ 55.13 $ 41 |
Summary of Activity Related to Employee Restricted Share Units | Employee RSU Weighted Average Grant Date FV Aggregate intrinsic value Outstanding as at December 31, 2022 508,468 $ 56.25 $ 30 Granted including DRIP 236,537 52.07 Exercised (171,537) 54.62 Forfeited (10,827) 54.76 Outstanding as at December 31, 2023 562,641 $ 55.01 $ 32 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Variable Interest Entities [Abstract] | |
Summary of Material Unconsolidated Variable Interest Entities | As at December 31, 2023 December 31, 2022 Maximum Maximum millions of dollars Total assets exposure to loss Total assets loss Unconsolidated VIEs in which Emera has variable interests NSPML (equity accounted) $ 489 $ 6 $ 501 $ 6 |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Nature of Operations) (Narrative) (Details) $ in Billions | 12 Months Ended |
Dec. 31, 2023 CAD ($) Customers MW km | |
NSP Maritime Link Inc. | Equity Method Investee | NSP Maritime Link Inc Project | |
Nature of operations [Line items] | |
100% ownership | 100% |
Labrador-Island Link Limited Partnership | Equity Method Investee | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 31% |
Maritimes and Northeast Pipeline | Equity Method Investee | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 12.90% |
Maritimes and Northeast Pipeline | Operating | Gas Utilities and Infrastructure | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 12.90% |
Length Of Pipeline | km | 1,400 |
St. Lucia Electricity Services Limited | Equity Method Investee | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 19.50% |
St. Lucia Electricity Services Limited | Operating | Other Electric Utilities | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 19.50% |
Bear Swamp Power Company LLC | Equity Method Investee | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 50% |
Tampa Electric | Operating | Florida Electric Utility | |
Nature of operations [Line items] | |
Number of Customers | 840,000 |
Nova Scotia Power Inc. | Operating | Canadian Electric Utilities | |
Nature of operations [Line items] | |
Number of Customers | 549,000 |
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities | |
Nature of operations [Line items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 824 |
Emera Newfoundland and Labrador Holdings Inc. | Operating | Canadian Electric Utilities | NSP Maritime Link Inc Project | |
Nature of operations [Line items] | |
100% ownership | 100% |
Emera Newfoundland and Labrador Holdings Inc. | NSP Maritime Link Inc. | Operating | Canadian Electric Utilities | |
Nature of operations [Line items] | |
Public Utilities, Equipment, Transmission and Distribution | $ | $ 1.8 |
Length Of Pipeline | km | 170 |
Emera Newfoundland and Labrador Holdings Inc. | Labrador-Island Link Limited Partnership | Operating | Canadian Electric Utilities | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 31% |
Public Utilities, Equipment, Transmission and Distribution | $ | $ 3.7 |
Barbados Light and Power Company Limited | Operating | Other Electric Utilities | |
Nature of operations [Line items] | |
Number of Customers | 134,000 |
Grand Bahama Power Company Limited | Operating | Other Electric Utilities | |
Nature of operations [Line items] | |
Number of Customers | 19,000 |
Peoples Gas System Division | Gas Utilities and Infrastructure | |
Nature of operations [Line items] | |
Number of Customers | 490,000 |
New Mexico Gas Company | Gas Utilities and Infrastructure | |
Nature of operations [Line items] | |
Number of Customers | 540,000 |
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | |
Nature of operations [Line items] | |
Length Of Pipeline | km | 145 |
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life | 25 years |
Emera Brunswick Pipeline Company Limited | Operating | Gas Utilities and Infrastructure | |
Nature of operations [Line items] | |
Length Of Pipeline | km | 145 |
Emera Energy | Bear Swamp Power Company LLC | Other | |
Nature of operations [Line items] | |
Equity Method Investment, Ownership Percentage | 50% |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 660 |
Brooklyn Power Corporation | Operating | Other | |
Nature of operations [Line items] | |
Public Utilities Property Plant And Equipment Generation Capacity | MW | 30 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies (Narrative) (Details) | 12 Months Ended | ||||
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2022 CAD ($) | Dec. 31, 2021 CAD ($) | |
Asset Impairment Charges | |||||
Impairment charge | $ 0 | $ 73,000,000 | |||
Goodwill | |||||
Goodwill | 5,871,000,000 | $ 6,012,000,000 | $ 5,696,000,000 | ||
Goodwill impairment charge | $ 0 | 73,000,000 | |||
Lease, Practical Expedient, Lessor Single Lease Component [true false] | true | ||||
Long-Lived Assets | |||||
Asset Impairment Charges | |||||
Impairment charge | $ 0 | 0 | |||
Equity Method Investments | |||||
Asset Impairment Charges | |||||
Impairment charge | 0 | 0 | |||
Financial Assets | |||||
Asset Impairment Charges | |||||
Impairment charge | 0 | 0 | |||
TECO Energy | |||||
Goodwill | |||||
Goodwill | 5,868,000,000 | ||||
GBPC | |||||
Goodwill | |||||
Goodwill | |||||
Goodwill impairment charge | $ 73,000,000 | ||||
NMGC | |||||
Goodwill | |||||
Goodwill impairment charge | $ 0 |
Dispositions (Narrative) (Detai
Dispositions (Narrative) (Details) | Mar. 31, 2022 |
Dolmec [Member] | Disposition | |
Details of the assets and liabilities classified as held for sale [Line items] | |
Sale of ownership interest | 51.90% |
Segment Information (Reportable
Segment Information (Reportable Segments) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | $ 7,563 | $ 7,588 | |
OM&G | 1,879 | 1,596 | |
Provincial, state and municipal taxes | 433 | 367 | |
Depreciation and amortization | 1,049 | 952 | |
Income from equity investments | 146 | 129 | |
Other income (expenses), net | 158 | 145 | |
Interest expense, net | 925 | 709 | |
GBPC Impairment charge | 0 | 73 | |
Income tax expense (recovery) | 128 | 185 | |
Non-controlling interest in subsidiaries | 1 | 1 | |
Preferred stock dividends | 66 | 63 | |
Net income (loss) attributable to common shareholders | 977.7 | 945.1 | |
Capital expenditures | 2,921 | 2,575 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 39,480 | 39,742 | |
Investments subject to significant influence | 1,402 | 1,418 | |
Goodwill | 5,871 | 6,012 | $ 5,696 |
Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 5,746 | 5,473 | |
Fuel for generation and purchased power | 1,881 | 2,171 | |
Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 1,489 | 1,681 | |
Fuel for generation and purchased power | 527 | 800 | |
Florida Electric Utility | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 3,548 | 3,280 | |
Canadian Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 1,671 | 1,675 | |
Gas Utilities and Infrastructure | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 1,510 | 1,697 | |
Other Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 526 | 518 | |
Other | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 308 | 418 | |
Operating | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 7,563 | 7,588 | |
Operating | Florida Electric Utility | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 3,556 | 3,287 | |
OM&G | 830 | 625 | |
Provincial, state and municipal taxes | 289 | 235 | |
Depreciation and amortization | 571 | 507 | |
Income from equity investments | 0 | 0 | |
Other income (expenses), net | 69 | 68 | |
Interest expense, net | 271 | 185 | |
GBPC Impairment charge | 0 | ||
Income tax expense (recovery) | 117 | 121 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Preferred stock dividends | 0 | 0 | |
Net income (loss) attributable to common shareholders | 627 | 596 | |
Capital expenditures | 1,736 | 1,425 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 21,119 | 21,053 | |
Investments subject to significant influence | 0 | 0 | |
Goodwill | 4,628 | 4,739 | |
Operating | Florida Electric Utility | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 920 | 1,086 | |
Operating | Florida Electric Utility | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Operating | Canadian Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 1,671 | 1,675 | |
OM&G | 384 | 338 | |
Provincial, state and municipal taxes | 45 | 43 | |
Depreciation and amortization | 276 | 259 | |
Income from equity investments | 109 | 87 | |
Other income (expenses), net | 32 | 24 | |
Interest expense, net | 170 | 136 | |
GBPC Impairment charge | 0 | ||
Income tax expense (recovery) | (9) | (8) | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Preferred stock dividends | 0 | 0 | |
Net income (loss) attributable to common shareholders | 247 | 215 | |
Capital expenditures | 450 | 507 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 8,634 | 8,223 | |
Investments subject to significant influence | 1,236 | 1,241 | |
Goodwill | 0 | 0 | |
Operating | Canadian Electric Utilities | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 699 | 803 | |
Operating | Canadian Electric Utilities | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Operating | Gas Utilities and Infrastructure | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 1,524 | 1,704 | |
OM&G | 405 | 365 | |
Provincial, state and municipal taxes | 91 | 83 | |
Depreciation and amortization | 126 | 118 | |
Income from equity investments | 21 | 21 | |
Other income (expenses), net | 11 | 13 | |
Interest expense, net | 129 | 81 | |
GBPC Impairment charge | 0 | ||
Income tax expense (recovery) | 64 | 70 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Preferred stock dividends | 0 | 0 | |
Net income (loss) attributable to common shareholders | 214 | 221 | |
Capital expenditures | 664 | 574 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 7,735 | 7,737 | |
Investments subject to significant influence | 118 | 128 | |
Goodwill | 1,240 | 1,270 | |
Operating | Gas Utilities and Infrastructure | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Operating | Gas Utilities and Infrastructure | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 527 | 800 | |
Operating | Other Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 526 | 518 | |
OM&G | 130 | 123 | |
Provincial, state and municipal taxes | 3 | 3 | |
Depreciation and amortization | 68 | 61 | |
Income from equity investments | 4 | 4 | |
Other income (expenses), net | 7 | 0 | |
Interest expense, net | 23 | 19 | |
GBPC Impairment charge | 73 | ||
Income tax expense (recovery) | 0 | 0 | |
Non-controlling interest in subsidiaries | 1 | 1 | |
Preferred stock dividends | 0 | 0 | |
Net income (loss) attributable to common shareholders | 37 | (48) | |
Capital expenditures | 63 | 63 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 1,311 | 1,337 | |
Investments subject to significant influence | 48 | 49 | |
Goodwill | 0 | 0 | |
Operating | Other Electric Utilities | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 275 | 290 | |
Operating | Other Electric Utilities | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Operating | Other | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 339 | 440 | |
OM&G | 151 | 156 | |
Provincial, state and municipal taxes | 5 | 3 | |
Depreciation and amortization | 8 | 7 | |
Income from equity investments | 12 | 17 | |
Other income (expenses), net | 20 | 23 | |
Interest expense, net | 332 | 288 | |
GBPC Impairment charge | 0 | ||
Income tax expense (recovery) | (44) | 2 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Preferred stock dividends | 66 | 63 | |
Net income (loss) attributable to common shareholders | (147) | (39) | |
Capital expenditures | 8 | 6 | |
Segment Reporting Information, As at December 31 | |||
Total assets | 1,938 | 2,835 | |
Investments subject to significant influence | 0 | 0 | |
Goodwill | 3 | 3 | |
Operating | Other | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Operating | Other | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Intersegment Eliminations | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | (53) | (36) | |
OM&G | (21) | (11) | |
Provincial, state and municipal taxes | 0 | 0 | |
Depreciation and amortization | 0 | 0 | |
Income from equity investments | 0 | 0 | |
Other income (expenses), net | 19 | 17 | |
Interest expense, net | 0 | 0 | |
GBPC Impairment charge | 0 | ||
Income tax expense (recovery) | 0 | 0 | |
Non-controlling interest in subsidiaries | 0 | 0 | |
Preferred stock dividends | 0 | 0 | |
Net income (loss) attributable to common shareholders | 0 | 0 | |
Capital expenditures | 0 | 0 | |
Segment Reporting Information, As at December 31 | |||
Total assets | (1,257) | (1,443) | |
Investments subject to significant influence | 0 | 0 | |
Goodwill | 0 | 0 | |
Financing costs | 95 | 13 | |
Intersegment Eliminations | Regulated | Electric Revenue | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | (13) | (8) | |
Intersegment Eliminations | Regulated | Natural gas | |||
Segment Reporting Information, For the year ended December 31 | |||
Fuel for generation and purchased power | 0 | 0 | |
Eliminations | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | (53) | (36) | |
Eliminations | Florida Electric Utility | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 8 | 7 | |
Eliminations | Canadian Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 0 | 0 | |
Eliminations | Gas Utilities and Infrastructure | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 14 | 7 | |
Eliminations | Other Electric Utilities | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | 0 | 0 | |
Eliminations | Other | |||
Segment Reporting Information, For the year ended December 31 | |||
Total operating revenues | $ 31 | $ 22 |
Segment Information (Geographic
Segment Information (Geographical) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | $ 7,563 | $ 7,588 |
Property, Plant and Equipment, Net | 24,376 | 22,996 |
Canada | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 1,727 | 1,725 |
Property, Plant and Equipment, Net | 4,878 | 4,689 |
United States | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 5,310 | 5,346 |
Property, Plant and Equipment, Net | 18,588 | 17,382 |
Barbados | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 389 | 384 |
Property, Plant and Equipment, Net | 576 | 583 |
The Bahamas | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | 137 | 122 |
Property, Plant and Equipment, Net | 334 | 342 |
Dominica | ||
Revenues from External Customers and Long-Lived Assets [Line Items] | ||
Revenues | $ 0 | $ 11 |
Segment Information (Narrative)
Segment Information (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2023 | |
Segment Information [Abstract] | |
Segment Reporting, Factors Used to Identify Entity's Reportable Segments | Emera manages its reportable segments separately due in part to their different operating, regulatory and geographical environments. Segments are reported based on each subsidiary’s contribution of revenues, net income attributable to common shareholders and total assets, as reported to the Company’s chief operating decision maker. |
Revenue (Disaggregation of Reve
Revenue (Disaggregation of Revenue by Major Source) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | $ 7,563 | $ 7,588 |
Total operating revenues | 7,563 | 7,588 |
Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 3,548 | 3,280 |
Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 1,671 | 1,675 |
Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 526 | 518 |
Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 1,510 | 1,697 |
Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 308 | 418 |
Operating | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 7,563 | 7,588 |
Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 3,556 | 3,287 |
Total operating revenues | 3,556 | 3,287 |
Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 1,671 | 1,675 |
Total operating revenues | 1,671 | 1,675 |
Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 526 | 518 |
Total operating revenues | 526 | 518 |
Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 1,524 | 1,704 |
Total operating revenues | 1,524 | 1,704 |
Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 339 | 440 |
Total operating revenues | 339 | 440 |
Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (53) | (36) |
Total operating revenues | (53) | (36) |
Eliminations | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 8 | 7 |
Eliminations | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Eliminations | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Eliminations | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 14 | 7 |
Eliminations | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 31 | 22 |
Regulated | Other Electric And Regulatory | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 254 | 335 |
Non-Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 328 | 434 |
Total operating revenues | 328 | 434 |
Non-Regulated | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Non-Regulated | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Non-Regulated | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Non-Regulated | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 21 | 16 |
Non-Regulated | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 339 | 440 |
Non-Regulated | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (32) | (22) |
Electric Revenue | Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 7,235 | 7,154 |
Total operating revenues | 5,746 | 5,473 |
Electric Revenue | Regulated | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 3,556 | 3,287 |
Electric Revenue | Regulated | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 1,671 | 1,675 |
Electric Revenue | Regulated | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 526 | 518 |
Electric Revenue | Regulated | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 1,503 | 1,688 |
Electric Revenue | Regulated | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (21) | (14) |
Electric Revenue | Regulated | Residential | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 4,124 | 3,617 |
Electric Revenue | Regulated | Residential | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 2,307 | 1,799 |
Electric Revenue | Regulated | Residential | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 910 | 834 |
Electric Revenue | Regulated | Residential | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 183 | 184 |
Electric Revenue | Regulated | Residential | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 724 | 800 |
Electric Revenue | Regulated | Residential | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Residential | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Commercial | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 2,256 | 2,039 |
Electric Revenue | Regulated | Commercial | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 1,083 | 869 |
Electric Revenue | Regulated | Commercial | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 463 | 427 |
Electric Revenue | Regulated | Commercial | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 285 | 282 |
Electric Revenue | Regulated | Commercial | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 425 | 461 |
Electric Revenue | Regulated | Commercial | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Commercial | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Industrial | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 606 | 691 |
Electric Revenue | Regulated | Industrial | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 274 | 230 |
Electric Revenue | Regulated | Industrial | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 219 | 353 |
Electric Revenue | Regulated | Industrial | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 33 | 32 |
Electric Revenue | Regulated | Industrial | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 93 | 83 |
Electric Revenue | Regulated | Industrial | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Industrial | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (13) | (7) |
Electric Revenue | Regulated | Other Electric | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 443 | 432 |
Electric Revenue | Regulated | Other Electric | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 395 | 398 |
Electric Revenue | Regulated | Other Electric | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 41 | 28 |
Electric Revenue | Regulated | Other Electric | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 7 | 6 |
Electric Revenue | Regulated | Other Electric | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Other Electric | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Other Electric | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Regulatory Deferrals | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (510) | (21) |
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | (522) | (27) |
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 12 | 6 |
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Regulatory Deferrals | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Regulatory Deferrals | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue from contract with customer | 0 | 0 |
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 19 | 18 |
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 38 | 33 |
Electric Revenue | Regulated | Other Electric And Regulatory | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 6 | 8 |
Gas Revenue | Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 1,489 | 1,681 |
Gas Revenue | Regulated | Other Electric And Regulatory | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 199 | 283 |
Marketing and trading margin | Non-Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 96 | 143 |
Marketing and trading margin | Non-Regulated | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Marketing and trading margin | Non-Regulated | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Marketing and trading margin | Non-Regulated | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Marketing and trading margin | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Marketing and trading margin | Non-Regulated | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 96 | 143 |
Marketing and trading margin | Non-Regulated | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Energy sales | Non-Regulated | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Energy sales | Non-Regulated | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Energy sales | Non-Regulated | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Finance Income | Regulated | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 62 | 61 |
Finance Income | Regulated | Operating | Florida Electric Utility | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Finance Income | Regulated | Operating | Canadian Electric Utilities | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Finance Income | Regulated | Operating | Other Electric Utilities | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Finance Income | Regulated | Operating | Gas Utilities and Infrastructure | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 62 | 61 |
Finance Income | Regulated | Operating | Other | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Finance Income | Regulated | Eliminations | Repsol Energy Canada | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | |
Other revenue | Regulated | Other Electric And Regulatory | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 0 | 0 |
Other revenue | Regulated | Other Electric And Regulatory | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | (8) | (7) |
Other revenue | Non-Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 25 | 22 |
Other revenue | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 21 | 16 |
Other revenue | Non-Regulated | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | 27 | 16 |
Other revenue | Non-Regulated | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Total operating revenues | (23) | (10) |
Mark-To-Market | Non-Regulated | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 207 | 269 |
Mark-To-Market | Non-Regulated | Operating | Florida Electric Utility | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Mark-To-Market | Non-Regulated | Operating | Canadian Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Mark-To-Market | Non-Regulated | Operating | Other Electric Utilities | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Mark-To-Market | Non-Regulated | Operating | Gas Utilities and Infrastructure | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 0 | 0 |
Mark-To-Market | Non-Regulated | Operating | Other | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | 216 | 281 |
Mark-To-Market | Non-Regulated | Eliminations | ||
Disaggregation of Revenue [Line Items] | ||
Revenue which does not represent revenues from contracts with customers | $ (9) | $ (12) |
Revenue (Remaining Performance
Revenue (Remaining Performance Obligations) (Narrative) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 488 | $ 450 |
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year) | 2043 | |
SeaCoast Gas Transmission, LLC | PGS | ||
Revenue Remaining Performance Obligation Expected Timing Of Satisfaction [Line Items] | ||
Revenue, Remaining Performance Obligation, Amount | $ 134 | |
Revenue, Remaining Performance Obligation, Expected Timing Of Satisfaction (Year) | 2040 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities (Regulated Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Regulatory Assets [Line Items] | ||
Regulatory Assets, Current | $ 339 | $ 602 |
Regulatory Assets, Long-term | 2,766 | 3,018 |
Total regulatory assets | 3,105 | 3,620 |
Deferred income tax regulatory assets | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 1,233 | 1,166 |
TEC capital cost recovery for early retired assets | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 671 | 674 |
NSPI FAM | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 395 | 307 |
Pension and post-retirement medical plan | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 364 | 369 |
Cost Recovery Clauses | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 151 | 707 |
Deferrals related to derivative instruments | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 88 | 30 |
Storm cost recovery clauses | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 52 | 138 |
Environmental Remediations | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 26 | 27 |
Stranded Cost Recovery | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 25 | 27 |
NMGC winter event gas cost recovery | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | 0 | 69 |
Other | ||
Regulatory Assets [Line Items] | ||
Total regulatory assets | $ 100 | $ 106 |
Regulatory Assets and Liabili_4
Regulatory Assets and Liabilities (Regulated Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Regulatory Liabilities [Line Items] | ||
Regulatory Liability, Current | $ 168 | $ 495 |
Regulatory Liability, Long-term | 1,604 | 1,778 |
Total regulatory liabilities | 1,772 | 2,273 |
Accumulated reserve - COR | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 849 | 895 |
Deferred income tax regulatory liabilities | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 830 | 877 |
Cost Recovery Clauses | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 32 | 70 |
BLPC Self-insurance fund ("SIF") (note 32) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 29 | 30 |
Deferrals related to derivative instruments | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 17 | 230 |
NMGC gas hedge settlements (note 18) | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | 0 | 162 |
Other | ||
Regulatory Liabilities [Line Items] | ||
Total regulatory liabilities | $ 15 | $ 9 |
Regulatory Assets and Liabili_5
Regulatory Assets and Liabilities - Assets and Liabilities (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2022 USD ($) | Feb. 28, 2021 USD ($) | Jan. 31, 2020 USD ($) | Dec. 31, 2025 CAD ($) | Dec. 31, 2024 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Jun. 15, 2021 USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets | $ 3,105 | $ 3,620 | |||||||
NMGC winter event gas cost recovery | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets | $ 0 | $ 69 | |||||||
GBPC | Hurricane | Loss from Catastrophes | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Storm cost | $ 15 | ||||||||
Recovery Period | 5 years | ||||||||
GBPC | Steam turbine | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Public Utilities, Property, Plant and Equipment, Amount of Loss (Recovery) on Plant Abandonment | $ 21 | ||||||||
NSPI | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Storm cost | $ 10 | ||||||||
NSPI | Forecast | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Storm cost | $ 10 | $ 10 | |||||||
Tampa Electric | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Storm cost | $ 119 | $ 29 | |||||||
Recovery Period | 15 years | ||||||||
NMGC | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Recovery Period | 30 months | ||||||||
Incremental gas cost | $ 108 | ||||||||
NMGC | NMGC winter event gas cost recovery | |||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||
Regulatory Assets | $ 108 |
Regulatory Assets and Liabili_6
Regulatory Assets and Liabilities - Florida Electric Utility (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||
Nov. 17, 2023 USD ($) | Jan. 23, 2023 USD ($) | Jan. 19, 2022 USD ($) | Sep. 30, 2022 USD ($) | Sep. 30, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2023 USD ($) | Dec. 31, 2022 CAD ($) | Aug. 16, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||||||||||
State income tax | 11% | 11% | 15% | ||||||||
Utilities Operating Expense, Depreciation and Amortization | $ 1,049 | $ 952 | |||||||||
Regulatory Assets | 3,105 | 3,620 | |||||||||
Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Utilities Operating Expense, Depreciation and Amortization | 571 | 507 | |||||||||
Cost Recovery Clauses | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Regulatory Assets | 151 | 707 | |||||||||
Restoration Costs | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Regulatory Assets | 26 | 27 | |||||||||
Storm cost recovery clauses | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Regulatory Assets | $ 52 | $ 138 | |||||||||
Tampa Electric | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Storm Damage Provision | $ 119 | $ 29 | |||||||||
Recovery Period | 15 years | ||||||||||
Tampa Electric | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Estimated Amount of Investment | $ 876 | ||||||||||
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation | $ 91 | ||||||||||
Tampa Electric | Storm cost recovery clauses | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Storm Damage Provision | $ 35 | ||||||||||
Regulatory Assets | $ 131 | $ 134 | |||||||||
Approved reserve level | 56 | ||||||||||
Tampa Electric | Florida Public Service Commission | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Recovery Period | 15 years | ||||||||||
Tampa Electric | Florida Public Service Commission | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Disclosure of Rate Matters | TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. | TEC is regulated by the FPSC and is also subject to regulation by the Federal Energy Regulatory Commission. The FPSC sets rates at a level that allows utilities such as TEC to collect total revenues or revenue requirements equal to their cost of providing service, plus an appropriate return on invested capital. Base rates are determined in FPSC rate setting hearings which can occur at the initiative of TEC, the FPSC or other interested parties. | |||||||||
Allowed equity capital structure | 54% | 54% | |||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (22) | ||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 169 | ||||||||||
Tampa Electric | Florida Public Service Commission | Additional adjustment for 2026 | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (100) | ||||||||||
Tampa Electric | Florida Public Service Commission | Additional adjustment for 2027 | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (70) | ||||||||||
Tampa Electric | Florida Public Service Commission | Cost Recovery Clauses | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Approved regulated return on equity | 10.20% | 10.20% | 10.20% | ||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 518 | ||||||||||
Recovery Period | 21 months | ||||||||||
Tampa Electric | Florida Public Service Commission | Big Bend Modernization Project | Unit 1 components | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Property, Plant and Equipment, Plant in Service | $ 636 | ||||||||||
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation | $ 267 | ||||||||||
Tampa Electric | Florida Public Service Commission | Projected Fuel Costs | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ (170) | ||||||||||
Tampa Electric | Florida Public Service Commission | Range, Minimum | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Approved regulated return on equity | 9.25% | 9.25% | 9.25% | ||||||||
Tampa Electric | Florida Public Service Commission | Range, Minimum | Base rate effective January 2025 | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (290) | ||||||||||
Tampa Electric | Florida Public Service Commission | Range, Maximum | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Approved regulated return on equity | 11.25% | 11.25% | 11.25% | ||||||||
Tampa Electric | Florida Public Service Commission | Range, Maximum | Base rate effective January 2025 | Florida Electric Utility | Operating | |||||||||||
Public Utilities, General Disclosures [Line Items] | |||||||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ (320) |
Regulatory Assets and Liabili_7
Regulatory Assets and Liabilities - Canada Electric Utilities (Narrative) (Details) $ in Millions | 3 Months Ended | 12 Months Ended | 24 Months Ended | |||||||||
Jan. 29, 2024 CAD ($) | Dec. 01, 2023 CAD ($) | Oct. 31, 2023 CAD ($) | Aug. 15, 2021 | Jun. 30, 2023 CAD ($) | Dec. 31, 2024 | Dec. 31, 2023 CAD ($) km | Dec. 31, 2022 CAD ($) | Dec. 31, 2023 CAD ($) km | Dec. 21, 2023 CAD ($) | Mar. 31, 2023 CAD ($) | Feb. 28, 2022 CAD ($) | |
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Regulatory Liabilities | $ 1,772 | $ 2,273 | $ 1,772 | |||||||||
Utilities Operating Expense, Depreciation and Amortization | 1,049 | 952 | ||||||||||
Contractual Obligation, to be Paid, Year One | 2,698 | 2,698 | ||||||||||
Contractual Obligation, to be Paid, Year Two | 1,217 | 1,217 | ||||||||||
Regulatory Assets | 3,105 | 3,620 | 3,105 | |||||||||
Non-current assets | 11,396 | 11,850 | $ 11,396 | |||||||||
Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Utilities Operating Expense, Depreciation and Amortization | 276 | 259 | ||||||||||
NSPI | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Storm cost | $ 10 | |||||||||||
NSPI | Canadian Electric Utilities | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Recovery Period | 3 years | 3 years | ||||||||||
NSPI | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 6.90% | |||||||||||
Storm cost | $ 31 | |||||||||||
Deferred storm rider | $ 21 | $ 21 | ||||||||||
NSPI | Canadian Electric Utilities | Operating | Nova Scotia Cap-and-Trade ("Cap-and-Trade") Program | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Gas costs | 166 | |||||||||||
Credits purchased from provincial auctions | $ 6 | |||||||||||
Compliance costs accrued | $ (166) | |||||||||||
NSPI | Canadian Electric Utilities | Operating | Subsequent Event [Member] | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Requested approval for sale of regulatory assets | $ 117 | |||||||||||
Amortization and financing costs | $ 117 | |||||||||||
Collection period of amortization and financing costs | 10 years | |||||||||||
NSPI | Range, Minimum | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Approved regulated return on equity | 8.75% | 8.75% | ||||||||||
NSPI | Range, Maximum | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Approved regulated return on equity | 9.25% | 9.25% | ||||||||||
Regulated common equity component | 40% | |||||||||||
NSPI | Scenario Plan | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Public Utilities, Requested Rate Increase (Decrease), Amended, Percentage | 6.50% | |||||||||||
NSPI | NSPI FAM | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Increase to regulatory assets | $ 51 | |||||||||||
NSPI | UARB | Canadian Electric Utilities | Operating | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Amount requested to defer operating costs incurred from storm restoration | $ 24 | |||||||||||
Non-current assets | $ 24 | 24 | ||||||||||
NSPI | UARB | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Holdback payable | $ 4 | $ 8 | $ 12 | |||||||||
Estimate of possible percentage of receiving deliveries | 90% | 90% | ||||||||||
Monthly holdback amount | $ 4 | $ 2 | ||||||||||
Percent of contracted annual amount | 10% | 10% | ||||||||||
Emera Newfoundland and Labrador Holdings Inc. | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Public Utilities, Equipment, Transmission and Distribution | $ 1,800 | $ 1,800 | ||||||||||
Number of pipelines | 2 | |||||||||||
Length Of Pipeline | km | 170 | 170 | ||||||||||
Regulatory Liabilities | $ 1,800 | |||||||||||
Costs not recoverable for rate approval | 9 | |||||||||||
Costs not recoverable for rate approval net of tax | $ 7 | |||||||||||
Holdback payable | $ 4 | |||||||||||
Contractual Obligation, to be Paid, Year One | $ 164 | $ 164 | $ 164 | |||||||||
Energy Delivery Commitments and Contracts, Term | 35 years | |||||||||||
Emera Newfoundland and Labrador Holdings Inc. | Range, Minimum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Approved regulated return on equity | 8.75% | |||||||||||
Emera Newfoundland and Labrador Holdings Inc. | Range, Maximum | Canadian Electric Utilities | Operating | NSP Maritime Link Inc. | ||||||||||||
Public Utilities, General Disclosures [Line Items] | ||||||||||||
Approved regulated return on equity | 9.25% | |||||||||||
Equity ratio | 30% | 30% |
Regulatory Assets and Liabili_8
Regulatory Assets and Liabilities - Gas Utilities and Infrastructure (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | 24 Months Ended | ||||
Nov. 09, 2023 USD ($) | Sep. 14, 2023 USD ($) | May 20, 2022 | Feb. 28, 2021 USD ($) | Dec. 31, 2023 CAD ($) km | Dec. 31, 2022 CAD ($) | Dec. 31, 2023 USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||||||
Accumulated depreciation | $ 9,994 | $ 9,574 | |||||
Regulatory assets | 3,105 | 3,620 | |||||
Storm cost recovery clauses | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Regulatory assets | $ 52 | $ 138 | |||||
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Length Of Pipeline | km | 145 | ||||||
Emera Brunswick Pipeline Company Limited | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Length Of Pipeline | km | 145 | ||||||
Public Utilities, Property, Plant and Equipment, Transmission and Distribution, Useful Life | 25 years | ||||||
NMGC | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Incremental gas cost | $ 108 | ||||||
NMGC | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 9.375% | 9.375% | |||||
Allowed equity capital structure | 52% | 52% | |||||
NMGC | New Mexico Public Regulatory | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 10.50% | ||||||
Public Utilities, Requested Rate Increase (Decrease), Amount | $ 49 | ||||||
PGS | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed equity capital structure | 54.70% | ||||||
Accumulated Depreciation, Depletion and Amortization, Property, Plant and Equipment, Period Decrease | $ 20 | $ 14 | $ 34 | ||||
PGS | Gas Utilities and Infrastructure | Operating | Scenario Plan | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 10.15% | ||||||
Allowed equity capital structure | 54.70% | ||||||
Phase-in Plan, Amount of Capitalized Costs Recovered | $ 11 | ||||||
Public Utilities, Approved Rate Increase (Decrease), Amount | 118 | ||||||
PGS | Gas Utilities and Infrastructure | Operating | Cast Iron/Bare Steel Pipe Replacement | Scenario Plan | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Phase-in Plan, Amount of Capitalized Costs Recovered | $ 107 | ||||||
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 8.90% | ||||||
PGS | Range, Minimum | Gas Utilities and Infrastructure | Operating | Scenario Plan | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Allowed equity capital structure | 54.70% | ||||||
PGS | Range, Maximum | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 11% | ||||||
PGS | Mid Point | Gas Utilities and Infrastructure | Operating | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 9.90% | ||||||
BPLC | |||||||
Public Utilities, General Disclosures [Line Items] | |||||||
Approved regulated return on equity | 10% | 10% |
Regulatory Assets and Liabili_9
Regulatory Assets and Liabilities - Other Electric Utilities (Narrative) (Details) $ in Millions, $ in Millions | 1 Months Ended | 12 Months Ended | |||
Apr. 01, 2022 USD ($) | Sep. 30, 2022 USD ($) | Jan. 31, 2022 | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | |
Public Utilities, General Disclosures [Line Items] | |||||
Income tax (expense) recovery | $ (128) | $ (185) | |||
Regulatory liabilities | 1,772 | 2,273 | |||
Other Electric Utilities | Operating | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Income tax (expense) recovery | $ 0 | $ 0 | |||
Barbados Light and Power Company Limited | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved regulated return on equity | 10% | 10% | |||
Barbados Light and Power Company Limited | Other Electric Utilities | Operating | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Cost sharing ratio | 50% | ||||
Barbados Light and Power Company Limited | Fair Trading Commission | Other Electric Utilities | Operating | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved regulated return on equity | 11.75% | ||||
Allowed equity capital structure | 55% | ||||
Deferred Tax Liabilities, Regulatory Assets and Liabilities | $ 5 | ||||
Public Utilities, Interim Rate Increase (Decrease), Amount | 1 | ||||
Regulatory liabilities | 50 | ||||
Accumulated depreciation | $ 16 | ||||
GBPC | GBPA | Other Electric Utilities | Operating | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Public Utilities, Approved Rate Increase (Decrease), Amount | $ 3.5 | ||||
Approved regulated return on equity | 8.32% | 8.23% | |||
GBPC | GBPA | Other Electric Utilities | Operating | Scenario Plan | |||||
Public Utilities, General Disclosures [Line Items] | |||||
Approved regulated return on equity | 12.84% |
Investments Subject to Signif_3
Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2015 | |
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 1,402 | $ 1,418 | |
Income (loss) from equity investments and subsidiaries | 146 | 129 | |
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Other long-term liabilities | 820 | 825 | |
Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 1,402 | 1,418 | |
Income (loss) from equity investments and subsidiaries | 146 | 129 | |
Equity Method Investee | Emera Inc. | |||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity | 10 | ||
LIL | Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 747 | 740 | |
Income (loss) from equity investments and subsidiaries | $ 63 | 58 | |
Percentage of Ownership | 31% | ||
LIL | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 31% | ||
LIL | Equity Method Investee | Class B units | NSP Maritime Link Inc Project | |||
Schedule of Equity Method Investments [Line Items] | |||
100% ownership | 100% | ||
LIL | Equity Method Investee | Total Units Issued [Member] | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 24.50% | ||
NSPML | Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 489 | 501 | |
Income (loss) from equity investments and subsidiaries | $ 46 | 29 | |
NSPML | Equity Method Investee | NSP Maritime Link Inc Project | |||
Schedule of Equity Method Investments [Line Items] | |||
100% ownership | 100% | ||
M&NP | Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 118 | 128 | |
Income (loss) from equity investments and subsidiaries | $ 21 | 21 | |
Percentage of Ownership | 12.90% | ||
M&NP | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 12.90% | ||
Lucelec | Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | $ 48 | 49 | |
Income (loss) from equity investments and subsidiaries | $ 4 | 4 | |
Percentage of Ownership | 19.50% | ||
Lucelec | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 19.50% | ||
Bear Swamp | |||
Equity Method Investment, Summarized Financial Information [Abstract] | |||
Other long-term liabilities | $ 81 | 95 | $ 179 |
Bear Swamp | Equity Method Investee | |||
Schedule of Equity Method Investments [Line Items] | |||
Investments subject to significant influence | 0 | 0 | |
Income (loss) from equity investments and subsidiaries | $ 12 | $ 17 | |
Percentage of Ownership | 50% | ||
Bear Swamp | Equity Method Investee | Emera Inc. | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 50% | ||
Maritime Link And LIL | Plan, subject to approval | |||
Schedule of Equity Method Investments [Line Items] | |||
Percentage of Ownership | 49% |
Investments Subject to Signif_4
Investments Subject to Significant Influence and Equity Income (Summary of Investments Subject to Significant Influence - NSPML) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Balance Sheets | |||
Current assets | $ 3,708 | $ 4,896 | |
Property, plant and equipment | 24,376 | 22,996 | |
Regulatory assets | 2,766 | 3,018 | |
Non-current assets | 11,396 | 11,850 | |
Total assets | 39,480 | 39,742 | |
Current liabilities | 4,544 | 7,287 | |
Non-current liabilities | 22,848 | 21,014 | |
Equity | 12,088 | 11,441 | $ 10,150 |
Total liabilities and equity | 39,480 | 39,742 | |
Variable Interest Entity, Not Primary Beneficiary | NSPML | |||
Balance Sheets | |||
Current assets | 21 | 17 | |
Property, plant and equipment | 1,473 | 1,517 | |
Regulatory assets | 272 | 265 | |
Non-current assets | 29 | 29 | |
Total assets | 1,795 | 1,828 | |
Current liabilities | 48 | 48 | |
Long-term debt | 1,109 | 1,149 | |
Non-current liabilities | 149 | 130 | |
Equity | 489 | 501 | |
Total liabilities and equity | $ 1,795 | $ 1,828 |
Other Income, Net (Components o
Other Income, Net (Components of Other Expense, Net) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
Dec. 15, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | |
Other Income, Net [Abstract] | |||
Interest income | $ 43 | $ 25 | |
AFUDC | 38 | 52 | |
Pension non-current service cost recovery | 35 | 24 | |
FX gains (losses) | 20 | (26) | |
TECO Guatemala Holdings award | $ 63 | 0 | 63 |
Other | 22 | 7 | |
Other income (expenses), net | $ 158 | $ 145 |
Interest Expense, Net (Componen
Interest Expense, Net (Components of Interest Expense, Net) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Interest Expense, Net [Abstract] | ||
Interest on debt | $ 954 | $ 727 |
Allowance for borrowed funds used during construction | (16) | (21) |
Other | (13) | 3 |
Interest expense, net | $ 925 | $ 709 |
Income Taxes (Reconciliation of
Income Taxes (Reconciliation of Effective Income Tax Rate) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Income before provision for income taxes | $ 1,173 | $ 1,194 |
Statutory income tax rate | 29% | 29% |
Income taxes, at statutory income tax rates | $ 340 | $ 346 |
Deferred income taxes on regulated income recorded as regulatory assets and regulatory liabilities | (72) | (70) |
Tax credits | (53) | (18) |
Foreign tax rate variance | (36) | (44) |
Amortization of deferred income tax regulatory liabilities | (33) | (33) |
Tax effect of equity earnings | (15) | (10) |
GBPC impairment charge | 0 | 21 |
Other | (3) | (7) |
Income tax expense | $ 128 | $ 185 |
Effective income tax rate | 11% | 15% |
Regulatory Liabilities | $ 1,772 | $ 2,273 |
Incremental tax benefits payable to customers [Member] | ||
Regulatory Liabilities | $ 30 | $ 9 |
Income Taxes (Composition of Ta
Income Taxes (Composition of Taxes on Income from Continuing Operations) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Deferred income taxes | $ 97 | $ 152 |
Income tax expense | 128 | 185 |
Canada | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 26 | 25 |
Deferred income taxes | 93 | 122 |
Operating loss carry forwards | (93) | (94) |
United States | ||
Components of Income Tax Expense (Benefit), Continuing Operations [Abstract] | ||
Current income taxes | 5 | 8 |
Deferred income taxes | 128 | 252 |
Investment tax credits | (29) | (7) |
Operating loss carry forwards | $ (2) | $ (121) |
Income Taxes (Composition of In
Income Taxes (Composition of Income Before Provision for Income Taxes) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | $ 1,173 | $ 1,194 |
Canada | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | 171 | 173 |
United States | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | 964 | 1,063 |
Other | ||
Composition of taxes on income from continuing operations [Line items] | ||
Income before provision for income taxes | $ 38 | $ (42) |
Income Taxes (Schedule of Defer
Income Taxes (Schedule of Deferred Income Tax Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Deferred income tax assets: | ||
Tax loss carryforwards | $ 1,195 | $ 1,207 |
Tax credit carryforwards | 454 | 415 |
Derivative instruments | 205 | 45 |
Regulatory liabilities | 175 | 264 |
Other | 372 | 341 |
Total deferred income tax assets before valuation allowance | 2,401 | 2,272 |
Valuation allowance | (363) | (312) |
Total deferred income tax assets after valuation allowance | 2,038 | 1,960 |
Deferred income tax (liabilities): | ||
PP&E | (3,223) | (2,981) |
Derivative instruments | (235) | (125) |
Investments subject to significant influence | (216) | (181) |
Regulatory assets | (196) | (310) |
Other | (312) | (322) |
Total deferred income tax liabilities | (4,182) | (3,919) |
Consolidated Balance Sheets presentation: | ||
Long-term deferred income tax assets | 208 | 237 |
Long-term deferred income tax liabilities | (2,352) | (2,196) |
Net deferred income tax liabilities | $ (2,144) | $ (1,959) |
Income Taxes (Net Operating Los
Income Taxes (Net Operating Loss ("NOL"), Capital Loss and Tax Credit Carryforwards and Their Expiration Periods) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) | |
Canada | Capital loss | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 73 |
Subject to Valuation Allowance | (73) |
Net Tax Credit Carryforwards | $ 0 |
Expiration period | Indefinite |
Canada | NOL | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 2,914 |
Subject to Valuation Allowance | (1,164) |
Net Tax Credit Carryforwards | $ 1,750 |
Expiration period | 2026 - 2043 |
United States | NOL | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 1,360 |
Subject to Valuation Allowance | (1) |
Net Tax Credit Carryforwards | $ 1,359 |
Expiration period | 2036 - Indefinite |
United States | Tax credit | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 454 |
Subject to Valuation Allowance | (3) |
Net Tax Credit Carryforwards | $ 451 |
Expiration period | 2025 - 2043 |
State | NOL | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 1,003 |
Subject to Valuation Allowance | (1) |
Net Tax Credit Carryforwards | $ 1,002 |
Expiration period | 2026 - Indefinite |
Other | NOL | |
Composition of taxes on income from continuing operations [Line items] | |
Gross Tax Carryforwards | $ 81 |
Subject to Valuation Allowance | (28) |
Net Tax Credit Carryforwards | $ 53 |
Expiration period | 2024 - 2030 |
Income Taxes (Details of Change
Income Taxes (Details of Change in Unrecognized Tax Benefits) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward] | ||
Beginning, January 1 | $ 33 | $ 28 |
Increases due to tax positions related to current year | 5 | 5 |
Increases due to tax positions related to a prior year | 1 | 2 |
Decreases due to tax positions related to a prior year | (2) | (2) |
Balance, December 31 | $ 37 | $ 33 |
Income Taxes (Unrecognized tax
Income Taxes (Unrecognized tax benefits) (Details) - CAD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Significant Change in Unrecognized Tax Benefits is Reasonably Possible [Line Items] | ||
Temporary Differences/Potential change | $ 4,700,000,000 | $ 3,800,000,000 |
Net amount in dispute | 126,000,000 | 126,000,000 |
Prepaid amount in dispute | 55,000,000 | |
Deferred Tax Assets, Allowance | 363,000,000 | 312,000,000 |
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract] | ||
Amount that could affect effective tax rate | 37,000,000 | 33,000,000 |
Accrued interest | 9,000,000 | 7,000,000 |
Income Tax Examination, Interest Expense | 2,000,000 | $ 1,000,000 |
Accrued penalties | $ 0 |
Common Stock (Summary of Issued
Common Stock (Summary of Issued and Outstanding Common Stock) (Details) - CAD ($) shares in Thousands, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Beginning Balance | $ 7,762 | |
Issuance of common stock | 397 | $ 248 |
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP") | 32 | 36 |
Ending Balance | $ 8,462 | $ 7,762 |
Increase (Decrease) in Stockholders' Equity [Roll Forward] | ||
Beginning Balance | 269,950 | 261,070 |
Issuance of common stock (shares) | 8,290 | 4,070 |
Issued under Purchase Plans at market rate | 5,260 | 4,210 |
Options exercised under senior management share option plan | 620 | 600 |
Ending Balance | 284,120 | 269,950 |
Common Stock | ||
Increase (Decrease) In Common Stock Value [Roll Forward] | ||
Beginning Balance | $ 7,762 | $ 7,242 |
Issuance of common stock | 397 | 248 |
Issued under Purchase Plans at market rate | 272 | 238 |
Senior management stock options exercised and Employee Share Purchase Plan ("ECSPP") | 31 | 34 |
Ending Balance | $ 8,462 | $ 7,762 |
Common Stock (Narrative) (Detai
Common Stock (Narrative) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Debt Instrument [Line Items] | ||
Issuance of common stock (shares) | 8,290,000 | 4,070,000 |
Gross proceeds from Issuance of Common Stock | $ 424 | $ 277 |
Percentage of outstanding stock maximum | 10% | |
ATM Program | ||
Debt Instrument [Line Items] | ||
Maximum common stock issued from treasury amount | $ 600 | |
ATM Program | Common Stock | ||
Debt Instrument [Line Items] | ||
Issuance of common stock (shares) | 8,287,037 | 4,072,469 |
Gross proceeds from Issuance of Common Stock | $ 400 | $ 250 |
Net proceeds from issuance of common stock | $ 397 | $ 248 |
Average price per share, issued | $ 48.27 | $ 61.31 |
Employee Stock Option Plan | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 6,000,000 | 6,000,000 |
Share Unit Plans | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 2,000,000 | 2,700,000 |
Dividend Reinvestment | ||
Debt Instrument [Line Items] | ||
Common Stock, Capital Shares Reserved for Future Issuance | 18,000,000 | 10,000,000 |
Earnings Per Share (Computation
Earnings Per Share (Computation of Basic and Diluted Earnings per Share) (Details) - CAD ($) $ / shares in Units, shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Numerator | ||
Net income attributable to common shareholders | $ 977.7 | $ 945.1 |
Diluted numerator | $ 977.7 | $ 945.1 |
Denominator | ||
Weighted average shares of common stock outstanding - basic | 273.6 | 265.5 |
Stock-based compensation | 0.2 | 0.4 |
Weighted average shares of common stock outstanding- diluted | 273.8 | 265.9 |
Earnings per common share | ||
Basic | $ 3.57 | $ 3.56 |
Diluted | $ 3.57 | $ 3.55 |
Accumulated Other Comprehensi_3
Accumulated Other Comprehensive Income (Components of Accumulated Other Comprehensive Income) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | $ 11,441 | $ 10,150 |
Net current period other comprehensive income (loss) | (273) | 553 |
Ending Balance | 12,088 | 11,441 |
Accumulated Other Comprehensive Income (Loss) | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 578 | 25 |
Other comprehensive income (loss) before reclassifications | (232) | 531 |
Amounts reclassified from accumulated other comprehensive income loss | (41) | 22 |
Net current period other comprehensive income (loss) | (273) | 553 |
Ending Balance | 305 | 578 |
Unrealized (loss) gain on translation of self-sustaining foreign operations | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 639 | 10 |
Other comprehensive income (loss) before reclassifications | (270) | 629 |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | (270) | 629 |
Ending Balance | 369 | 639 |
Net change in net investment hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (62) | 35 |
Other comprehensive income (loss) before reclassifications | 38 | (97) |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | 38 | (97) |
Ending Balance | (24) | (62) |
Losses on derivatives recognized as cash flow hedges | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | 16 | 18 |
Other comprehensive income (loss) before reclassifications | 0 | |
Amounts reclassified from accumulated other comprehensive income loss | (2) | (2) |
Net current period other comprehensive income (loss) | (2) | (2) |
Ending Balance | 14 | 16 |
Net change on available-for-sale investments | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (2) | (1) |
Other comprehensive income (loss) before reclassifications | 0 | (1) |
Amounts reclassified from accumulated other comprehensive income loss | 0 | 0 |
Net current period other comprehensive income (loss) | 0 | (1) |
Ending Balance | (2) | (2) |
Net change in unrecognized pension and post-retirement benefit costs | ||
Accumulated Other Comprehensive Income (Loss) [Line Items] | ||
Beginning Balance | (13) | (37) |
Other comprehensive income (loss) before reclassifications | 0 | 0 |
Amounts reclassified from accumulated other comprehensive income loss | (39) | 24 |
Net current period other comprehensive income (loss) | (39) | 24 |
Ending Balance | $ (52) | $ (13) |
Accumulated Other Comprehensi_4
Accumulated Other Comprehensive Income (Reclassifications out of Accumulated Other Comprehensive Income (Loss)) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Total operating revenues | $ 7,563 | $ 7,588 |
Interest expense, net (note 9) | (925) | (709) |
Other income, net (note 8) | 158 | 145 |
Income tax (expense) recovery | (128) | (185) |
Net income | 1,045 | 1,009 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Net income | (41) | 22 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Income tax (expense) recovery | (1) | (1) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Losses (gain) on derivatives recognized as cash flow hedges | Interest rate hedge | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Interest expense, net (note 9) | (2) | (2) |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Net change in unrecognized pension and post-retirement benefit costs | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Total before tax | (38) | 25 |
Income tax (expense) recovery | 1 | 1 |
Net income | (39) | 24 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Actuarial (gains) losses | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Other income, net (note 8) | 0 | 10 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Past service costs (gains) | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Other income, net (note 8) | 2 | 0 |
Reclassification out of Accumulated Other Comprehensive Income [Member] | Amounts reclassified into obligations | ||
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items] | ||
Pension and post-retirement benefits | $ (40) | $ 15 |
Inventory (Components of Invent
Inventory (Components of Inventory) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Inventory [Abstract] | ||
Fuel | $ 382 | $ 404 |
Materials | 408 | 365 |
Inventory Total | $ 790 | $ 769 |
Derivatives Instruments (Deriva
Derivatives Instruments (Derivative Assets and Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
HFT derivatives | ||
Derivative Assets | $ 348 | $ 429 |
Derivative Liabilities | 567 | 1,301 |
Other derivatives | ||
Other, Derivative Assets | 22 | 5 |
Other, Derivative Liabilities | 7 | 28 |
Derivative Assets | ||
Total gross current derivative assets | 389 | 690 |
Total impact of master netting agreements | (149) | (294) |
Derivative Asset, Total | 240 | 396 |
Derivative Assets, Current | 174 | 296 |
Derivative Assets, Long-term | 66 | 100 |
Derivative Liabilities | ||
Total gross current derivative liabilities | 653 | 1,372 |
Total impact of master netting agreements | (149) | (294) |
Derivative Liabilities, Total | 504 | 1,078 |
Derivative Liabilities, Current | 386 | 888 |
Derivative Liabilities, Long-term | 118 | 190 |
Equity derivatives | ||
Other derivatives | ||
Other, Derivative Assets | 4 | 0 |
Other, Derivative Liabilities | 0 | 5 |
FX forwards | ||
Other derivatives | ||
Other, Derivative Assets | 18 | 5 |
Other, Derivative Liabilities | 7 | 23 |
Power swaps and physical contracts | ||
HFT derivatives | ||
Derivative Assets | 29 | 89 |
Derivative Liabilities | 36 | 77 |
Natural gas swaps, futures, forwards, physical contracts | ||
HFT derivatives | ||
Derivative Assets | 319 | 340 |
Derivative Liabilities | 531 | 1,224 |
Regulatory deferral | ||
HFT derivatives | ||
Derivative Assets | 19 | 256 |
Derivative Liabilities | 79 | 43 |
Derivative Assets | ||
Total impact of master netting agreements | (3) | (18) |
Derivative Liabilities | ||
Total impact of master netting agreements | (3) | (18) |
Regulatory deferral | Commodity swaps and forwards | ||
Regulatory deferral | ||
Regulatory deferral, Derivative Assets | 16 | 186 |
Regulatory deferral, Derivative Liabilities | 76 | 42 |
Regulatory deferral | FX forwards | ||
HFT derivatives | ||
Derivative Assets | 3 | 18 |
Derivative Liabilities | 3 | 1 |
Regulatory deferral | Physical natural gas purchases and sales [Member] | ||
HFT derivatives | ||
Derivative Assets | 0 | 52 |
Derivative Liabilities | 0 | 0 |
HFT derivatives | ||
Derivative Assets | ||
Total impact of master netting agreements | (146) | (276) |
Derivative Liabilities | ||
Total impact of master netting agreements | $ (146) | $ (276) |
Derivatives Instruments (Cash F
Derivatives Instruments (Cash Flow Hedges Recorded in AOCI) (Details) - CAD ($) $ in Millions | 12 Months Ended | ||
May 26, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | |
Cash Flow Hedges | |||
Realized gain in interest expense, net | $ 2 | $ 2 | |
Total gains in net income | 2 | 2 | |
Total unrealized gain in AOCI - effective portion, net of tax | 14 | $ 16 | |
Unrealized gains currently in AOCI to be reclassified into net income within the next twelve months | $ 2 | ||
Cash flow hedges | Treasury lock | |||
Cash Flow Hedges | |||
Derivative gain loss amortization period | 10 years | ||
Total unrealized gain in AOCI - effective portion, net of tax | $ 19 |
Derivatives Instruments (Change
Derivatives Instruments (Changes in Realized and Unrealized Gains (Losses) on Derivatives Receiving Regulatory Deferral) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | $ 666 | $ (206) |
FX forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 17 | (24) |
Regulatory deferral | Physical natural gas purchases | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | (52) | (36) |
Regulatory deferral | Physical natural gas purchases | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 0 | 0 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Physical natural gas purchases | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (3) | 28 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Physical natural gas purchases | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Physical natural gas purchases | Regulated fuel for generation and purchased | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (49) | (64) |
Regulatory deferral | Physical natural gas purchases | Other | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | Commodity swaps and forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | (204) | 14 |
Regulatory deferral | Commodity swaps and forwards | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (109) | (69) |
Realized (gain) loss on derivatives receiving regulatory deferral | (5) | 48 |
Regulatory deferral | Commodity swaps and forwards | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (73) | 343 |
Realized (gain) loss on derivatives receiving regulatory deferral | 2 | (41) |
Regulatory deferral | Commodity swaps and forwards | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | 4 | (121) |
Regulatory deferral | Commodity swaps and forwards | Regulated fuel for generation and purchased | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (9) | (146) |
Regulatory deferral | Commodity swaps and forwards | Other | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (14) | 0 |
Regulatory deferral | FX forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Total change derivative instruments on derivatives receiving regulatory deferral | (17) | 18 |
Regulatory deferral | FX forwards | Regulatory Assets | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | (3) | 1 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | FX forwards | Regulatory Liabilities | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) on derivatives receiving regulatory deferral | 0 | 16 |
Realized (gain) loss on derivatives receiving regulatory deferral | 0 | 0 |
Regulatory deferral | FX forwards | Inventory | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (10) | 1 |
Regulatory deferral | FX forwards | Regulated fuel for generation and purchased | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | (4) | 0 |
Regulatory deferral | FX forwards | Other | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized (gain) loss on derivatives receiving regulatory deferral | $ 0 | $ 0 |
Derivatives Instruments (Notion
Derivatives Instruments (Notional Volumes of Outstanding Derivatives Designated for Regulatory Deferral) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) MMBTU MWh t | |
Commodity swaps and forwards | Coal | 2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | t | 1 |
Commodity swaps and forwards | Coal | 2025-2026 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | t | 0 |
Commodity swaps and forwards | Natural gas | 2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | 16 |
Commodity swaps and forwards | Natural gas | 2025-2026 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | 10 |
Commodity swaps and forwards | Power | 2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh | 1 |
Commodity swaps and forwards | Power | 2025-2026 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | MWh | 1 |
Physical natural gas purchases | Natural gas | 2024 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | 7 |
Physical natural gas purchases | Natural gas | 2025-2026 | |
Derivative [Line Items] | |
Natural Gas (Mmbtu) / Power (MWh) | MWh | 6 |
Foreign Exchange Swaps and Forward Contracts | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ | $ 241 |
Weighted average rate | 1.3155 |
% of USD requirements | 63% |
Foreign Exchange Swaps and Forward Contracts | 2025-2026 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives designated as cash flow hedges that are expected to settle | $ | $ 70 |
Weighted average rate | 1.3197 |
% of USD requirements | 17% |
Derivatives Instruments (Realiz
Derivatives Instruments (Realized and Unrealized Gains (Losses) on HFT Derivatives) (Details) - HFT derivatives - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ 1,037 | $ 64 |
Operating revenues | Power | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | (6) | 17 |
Operating revenues | Natural gas | Non-Regulated | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized and unrealized gains (losses) with respect to HFT derivatives | $ 1,043 | $ 47 |
Derivatives Instruments (Noti_2
Derivatives Instruments (Notional Volumes of Outstanding HFT Derivatives) (Details) - HFT derivatives MWh in Millions, MMBTU in Millions | 12 Months Ended |
Dec. 31, 2023 MWh MMBTU | |
Power | Purchases | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 1 |
Power | Purchases | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2026 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2027 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Purchases | 2028 and thereafter | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 1 |
Power | Sales | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2026 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2027 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Power | Sales | 2028 and thereafter | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MWh | 0 |
Natural gas | Purchases | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 296 |
Natural gas | Purchases | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 80 |
Natural gas | Purchases | 2026 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 50 |
Natural gas | Purchases | 2027 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 38 |
Natural gas | Purchases | 2028 and thereafter | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 30 |
Natural gas | Sales | 2024 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 338 |
Natural gas | Sales | 2025 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 86 |
Natural gas | Sales | 2026 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 16 |
Natural gas | Sales | 2027 | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 6 |
Natural gas | Sales | 2028 and thereafter | |
Derivative [Line Items] | |
Notional volumes of outstanding derivatives that are expected to settle | MMBTU | 4 |
Derivatives Instruments (Real_2
Derivatives Instruments (Realized and Unrealized Gains (Losses) on Other Derivatives) (Details) - CAD ($) shares in Millions, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Equity derivative hedges, return of shares | 2.9 | |
FX forwards | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized gains (loss) | $ 17 | $ (24) |
FX forwards | OM&G | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 0 | 0 |
Realized gains (loss) | 0 | 0 |
FX forwards | Other income, net | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 28 | (18) |
Realized gains (loss) | (11) | (6) |
Equity derivatives | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Realized gains (loss) | (9) | (22) |
Equity derivatives | OM&G | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 4 | (5) |
Realized gains (loss) | (13) | (17) |
Equity derivatives | Other income, net | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Unrealized gain (loss) | 0 | 0 |
Realized gains (loss) | $ 0 | $ 0 |
Derivatives Instruments (Credit
Derivatives Instruments (Credit Risk) (Narrative) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) Days | Dec. 31, 2022 CAD ($) | |
Credit Derivatives [Line Items] | ||
Total cash deposits/collateral on hand | $ 101 | $ 224 |
Financial Asset, Past Due [Member] | ||
Credit Derivatives [Line Items] | ||
Financial assets, considered to be past due | 142 | 131 |
Credit Concentration Risk | ||
Credit Derivatives [Line Items] | ||
Concentration Risk, maximum exposure | 1,200 | 1,900 |
Total cash deposits/collateral on hand | 310 | 386 |
Credit Concentration Risk | Receivables, net | ||
Credit Derivatives [Line Items] | ||
Fair Value, Financial assets, considered to be past due | $ 127 | $ 114 |
Average number of days financial asset outstanding | Days | 64 |
Derivatives Instruments (Summar
Derivatives Instruments (Summary of Concentration Risk) (Details) - Credit Concentration Risk - CAD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 1,200,000 | $ 1,900,000 |
Receivables, net | Other accounts receivable | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 151,000 | $ 585,000 |
% of total exposure | 10% | 25% |
Receivables, net | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 188,000 | $ 507,000 |
% of total exposure | 12% | 21% |
Receivables, net | Receivables | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 1,290,000 | $ 1,982,000 |
% of total exposure | 84% | 83% |
Receivables, net | Credit rating of A- or above | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 47,000 | $ 125,000 |
% of total exposure | 3% | 5% |
Receivables, net | Credit rating of BBB- to BBB+ | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 33,000 | $ 75,000 |
% of total exposure | 2% | 3% |
Receivables, net | Not rated | Trading group | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 108,000 | $ 307,000 |
% of total exposure | 7% | 13% |
Derivative Instruments (current and long-term) | Derivatives | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 240,000 | $ 396,000 |
% of total exposure | 16% | 17% |
Derivative Instruments (current and long-term) | Receivables and Derivatives | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 1,530,000 | $ 2,378,000 |
% of total exposure | 100% | 100% |
Derivative Instruments (current and long-term) | Credit rating of A- or above | Derivatives | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 138,000 | $ 202,000 |
% of total exposure | 9% | 9% |
Derivative Instruments (current and long-term) | Credit rating of BBB- to BBB+ | Derivatives | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 7,000 | $ 8,000 |
% of total exposure | 1% | 0% |
Derivative Instruments (current and long-term) | Not rated | Derivatives | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 95,000 | $ 186,000 |
% of total exposure | 6% | 8% |
Regulated utilities | Receivables, net | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 951,000 | $ 890,000 |
% of total exposure | 62% | 37% |
Regulated utilities | Receivables, net | Residential | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 476,000 | $ 455,000 |
% of total exposure | 31% | 19% |
Regulated utilities | Receivables, net | Commercial | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 194,000 | $ 192,000 |
% of total exposure | 13% | 8% |
Regulated utilities | Receivables, net | Industrial | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 84,000 | $ 121,000 |
% of total exposure | 5% | 5% |
Regulated utilities | Receivables, net | Other | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 103,000 | $ 122,000 |
% of total exposure | 7% | 5% |
Regulated utilities | Receivables, net | Cash Collateral | ||
Concentration Risk [Line Items] | ||
Concentration Risk, maximum exposure | $ 94,000 | $ 0 |
% of total exposure | 6% | 0% |
Derivatives Instruments (Cash C
Derivatives Instruments (Cash Collateral Positions) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Derivative Instruments | ||
Cash collateral provided to others | $ 101 | $ 224 |
Cash collateral received from others | 22 | 112 |
Total fair value of these derivatives, in a liability position | $ 504 | $ 1,078 |
FV Measurements (Classification
FV Measurements (Classification of Fair Value of Derivatives) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Assets | ||
Total assets | $ 240 | $ 396 |
Liabilities | ||
Total liabilities | 504 | 1,078 |
Level 3 | ||
Assets | ||
Total assets | 34 | 90 |
Liabilities | ||
Total liabilities | 365 | 826 |
Net assets (liabilities) | (331) | (736) |
Level 3 | Regulatory deferral | Physical natural gas purchases | ||
Assets | ||
Total assets | 52 | |
Liabilities | ||
Total liabilities | 0 | |
Level 3 | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | 4 | |
Liabilities | ||
Total liabilities | 1 | |
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Assets | ||
Total assets | 34 | 34 |
Liabilities | ||
Total liabilities | 365 | 825 |
Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 240 | 396 |
Liabilities | ||
Total liabilities | 504 | 1,078 |
Net assets (liabilities) | (264) | (682) |
Fair Value, Measurements, Recurring | Other | ||
Assets | ||
Total assets | 22 | |
Liabilities | ||
Total liabilities | 7 | |
Fair Value, Measurements, Recurring | FX forwards | Other | ||
Assets | ||
Total assets | 18 | 5 |
Liabilities | ||
Total liabilities | 7 | 23 |
Fair Value, Measurements, Recurring | Equity derivatives | Other | ||
Assets | ||
Total assets | 4 | |
Liabilities | ||
Total liabilities | 5 | |
Fair Value, Measurements, Recurring | Regulatory deferral | ||
Assets | ||
Total assets | 16 | 238 |
Liabilities | ||
Total liabilities | 76 | 25 |
Fair Value, Measurements, Recurring | Regulatory deferral | Commodity swaps and forwards | ||
Assets | ||
Total assets | 13 | 168 |
Liabilities | ||
Total liabilities | 73 | 24 |
Fair Value, Measurements, Recurring | Regulatory deferral | FX forwards | ||
Assets | ||
Total assets | 3 | 18 |
Liabilities | ||
Total liabilities | 3 | 1 |
Fair Value, Measurements, Recurring | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 52 | |
Fair Value, Measurements, Recurring | HFT derivatives | ||
Assets | ||
Total assets | 202 | 153 |
Liabilities | ||
Total liabilities | 421 | 1,025 |
Fair Value, Measurements, Recurring | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | 18 | 44 |
Liabilities | ||
Total liabilities | 24 | 31 |
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | ||
Assets | ||
Total assets | 184 | 109 |
Fair Value, Measurements, Recurring | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Liabilities | ||
Total liabilities | 397 | 994 |
Fair Value, Measurements, Recurring | Level 1 | ||
Assets | ||
Total assets | 48 | 132 |
Liabilities | ||
Total liabilities | 56 | 73 |
Net assets (liabilities) | (8) | 59 |
Fair Value, Measurements, Recurring | Level 1 | Other | ||
Assets | ||
Total assets | 4 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 1 | FX forwards | Other | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 1 | Equity derivatives | Other | ||
Assets | ||
Total assets | 4 | |
Liabilities | ||
Total liabilities | 5 | |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | ||
Assets | ||
Total assets | 7 | 120 |
Liabilities | ||
Total liabilities | 43 | 15 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Commodity swaps and forwards | ||
Assets | ||
Total assets | 7 | 120 |
Liabilities | ||
Total liabilities | 43 | 15 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | FX forwards | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 1 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | ||
Assets | ||
Total assets | 37 | 12 |
Liabilities | ||
Total liabilities | 13 | 53 |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | (5) | 9 |
Liabilities | ||
Total liabilities | 0 | 2 |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | ||
Assets | ||
Total assets | 42 | 3 |
Fair Value, Measurements, Recurring | Level 1 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Liabilities | ||
Total liabilities | 13 | 51 |
Fair Value, Measurements, Recurring | Level 2 | ||
Assets | ||
Total assets | 158 | 174 |
Liabilities | ||
Total liabilities | 83 | 179 |
Net assets (liabilities) | 75 | (5) |
Fair Value, Measurements, Recurring | Level 2 | Other | ||
Assets | ||
Total assets | 18 | |
Liabilities | ||
Total liabilities | 7 | |
Fair Value, Measurements, Recurring | Level 2 | FX forwards | Other | ||
Assets | ||
Total assets | 18 | 5 |
Liabilities | ||
Total liabilities | 7 | 23 |
Fair Value, Measurements, Recurring | Level 2 | Equity derivatives | Other | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | ||
Assets | ||
Total assets | 9 | 66 |
Liabilities | ||
Total liabilities | 33 | 10 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Commodity swaps and forwards | ||
Assets | ||
Total assets | 6 | 48 |
Liabilities | ||
Total liabilities | 30 | 9 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | FX forwards | ||
Assets | ||
Total assets | 3 | 18 |
Liabilities | ||
Total liabilities | 3 | 1 |
Fair Value, Measurements, Recurring | Level 2 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 0 | |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | ||
Assets | ||
Total assets | 131 | 103 |
Liabilities | ||
Total liabilities | 43 | 146 |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | 23 | 31 |
Liabilities | ||
Total liabilities | 24 | 28 |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | ||
Assets | ||
Total assets | 108 | 72 |
Fair Value, Measurements, Recurring | Level 2 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Liabilities | ||
Total liabilities | 19 | 118 |
Fair Value, Measurements, Recurring | Level 3 | ||
Assets | ||
Total assets | 34 | 90 |
Liabilities | ||
Total liabilities | 365 | 826 |
Net assets (liabilities) | (331) | (736) |
Fair Value, Measurements, Recurring | Level 3 | Other | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | FX forwards | Other | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Equity derivatives | Other | ||
Assets | ||
Total assets | 0 | |
Liabilities | ||
Total liabilities | 0 | |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | ||
Assets | ||
Total assets | 0 | 52 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Commodity swaps and forwards | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | FX forwards | ||
Assets | ||
Total assets | 0 | 0 |
Liabilities | ||
Total liabilities | 0 | 0 |
Fair Value, Measurements, Recurring | Level 3 | Regulatory deferral | Physical natural gas purchases and sales | ||
Assets | ||
Total assets | 52 | |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | ||
Assets | ||
Total assets | 34 | 38 |
Liabilities | ||
Total liabilities | 365 | 826 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | 0 | 4 |
Liabilities | ||
Total liabilities | 0 | 1 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards, physical contracts | ||
Assets | ||
Total assets | 34 | 34 |
Fair Value, Measurements, Recurring | Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Liabilities | ||
Total liabilities | $ 365 | $ 825 |
FV Measurements (Change in Fair
FV Measurements (Change in Fair Value of Level 3 Financial Assets) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 90 |
Realized gains included in fuel for generation and purchased power | (49) |
Unrealized gains included in regulatory liabilities | (3) |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (4) |
Ending Balance | 34 |
Regulatory deferral | Physical natural gas purchases | Energy Related derivative | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 52 |
Realized gains included in fuel for generation and purchased power | (49) |
Unrealized gains included in regulatory liabilities | (3) |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Ending Balance | 0 |
Not Designated as Hedging Instrument | Energy Related derivative | Non-regulated operating revenues | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 90 |
Realized gains included in fuel for generation and purchased power | (49) |
HFT derivatives | Energy Related derivative | Non-regulated operating revenues | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 90 |
Realized gains included in fuel for generation and purchased power | (49) |
Unrealized gains included in regulatory liabilities | (3) |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (4) |
Ending Balance | 34 |
HFT derivatives | Power | Energy Related derivative | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 4 |
Realized gains included in fuel for generation and purchased power | 0 |
Unrealized gains included in regulatory liabilities | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | (4) |
Ending Balance | 0 |
HFT derivatives | Natural gas | Energy Related derivative | |
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 34 |
Realized gains included in fuel for generation and purchased power | 0 |
Unrealized gains included in regulatory liabilities | 0 |
Total realized and unrealized gains (losses) included in non-regulated operating revenues | 0 |
Ending Balance | $ 34 |
FV Measurements (Change in Fa_2
FV Measurements (Change in Fair Value of Level 3 Financial Liabilities) (Details) - HFT derivatives - Energy Related derivative - Non-regulated operating revenues $ in Millions | 12 Months Ended |
Dec. 31, 2023 CAD ($) | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | $ 826 |
Total realized and unrealized gains included in non-regulated operating revenues | (461) |
Ending Balance | 365 |
Power | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 1 |
Total realized and unrealized gains included in non-regulated operating revenues | (1) |
Ending Balance | 0 |
Natural gas | |
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] | |
Beginning Balance | 825 |
Total realized and unrealized gains included in non-regulated operating revenues | (460) |
Ending Balance | $ 365 |
FV Measurements (Quantitative I
FV Measurements (Quantitative Information About Significant Unobservable Inputs Used in Level 3 Measurements) (Details) - CAD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Assets | ||
Total assets | $ 240,000,000 | $ 396,000,000 |
Liabilities | ||
Total liabilities | 504,000,000 | 1,078,000,000 |
Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 240,000,000 | 396,000,000 |
Liabilities | ||
Total liabilities | 504,000,000 | 1,078,000,000 |
Net liability | 264,000,000 | 682,000,000 |
Regulatory deferral | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 16,000,000 | 238,000,000 |
Liabilities | ||
Total liabilities | 76,000,000 | 25,000,000 |
HFT derivatives | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 202,000,000 | 153,000,000 |
Liabilities | ||
Total liabilities | 421,000,000 | 1,025,000,000 |
HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 18,000,000 | 44,000,000 |
Liabilities | ||
Total liabilities | 24,000,000 | 31,000,000 |
HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Total liabilities | 397,000,000 | 994,000,000 |
Level 3 | ||
Assets | ||
Total assets | 34,000,000 | 90,000,000 |
Liabilities | ||
Total liabilities | 365,000,000 | 826,000,000 |
Net liability | 331,000,000 | 736,000,000 |
Level 3 | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 34,000,000 | 90,000,000 |
Liabilities | ||
Total liabilities | 365,000,000 | 826,000,000 |
Net liability | 331,000,000 | 736,000,000 |
Level 3 | Regulatory deferral | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 0 | 52,000,000 |
Liabilities | ||
Total liabilities | 0 | 0 |
Level 3 | Regulatory deferral | Physical natural gas purchases | ||
Assets | ||
Total assets | 52,000,000 | |
Liabilities | ||
Total liabilities | $ 0 | |
Level 3 | Regulatory deferral | Range, Minimum | Physical natural gas purchases | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 5.79 | |
Level 3 | Regulatory deferral | Range, Maximum | Physical natural gas purchases | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 31.85 | |
Level 3 | Regulatory deferral | Weighted average | Physical natural gas purchases | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 12.27 | |
Level 3 | HFT derivatives | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 34,000,000 | $ 38,000,000 |
Liabilities | ||
Total liabilities | 365,000,000 | 826,000,000 |
Level 3 | HFT derivatives | Power swaps and physical contracts | ||
Assets | ||
Total assets | 4,000,000 | |
Liabilities | ||
Total liabilities | 1,000,000 | |
Level 3 | HFT derivatives | Power swaps and physical contracts | Fair Value, Measurements, Recurring | ||
Assets | ||
Total assets | 0 | 4,000,000 |
Liabilities | ||
Total liabilities | 0 | 1,000,000 |
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | ||
Assets | ||
Total assets | 34,000,000 | 34,000,000 |
Liabilities | ||
Total liabilities | 365,000,000 | 825,000,000 |
Level 3 | HFT derivatives | Natural gas swaps, futures, forwards and physical contracts | Fair Value, Measurements, Recurring | ||
Liabilities | ||
Total liabilities | $ 365,000,000 | $ 825,000,000 |
Level 3 | HFT derivatives | Range, Minimum | Power swaps and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 43.24 | |
Level 3 | HFT derivatives | Range, Minimum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 1.27 | 2.45 |
Level 3 | HFT derivatives | Range, Maximum | Power swaps and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 269.10 | |
Level 3 | HFT derivatives | Range, Maximum | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 16.25 | 33.88 |
Level 3 | HFT derivatives | Weighted average | Power swaps and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 138.79 | |
Level 3 | HFT derivatives | Weighted average | Natural gas swaps, futures, forwards and physical contracts | Third-party pricing | ||
Liabilities | ||
Derivative, measurement input | 4.85 | 12.01 |
FV Measurements (Financial Liab
FV Measurements (Financial Liabilities not Measured at Fair Value on Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Fair Value Measurement [Domain] | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | $ 16,621 | $ 14,670 |
Fair Value Measurement [Domain] | Level 1 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 0 | 0 |
Fair Value Measurement [Domain] | Level 2 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 16,363 | 14,284 |
Fair Value Measurement [Domain] | Level 3 | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 258 | 386 |
Carrying Amount | ||
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items] | ||
Financial assets and liabilities | 18,365 | 16,318 |
Financial assets and liabilities | $ 16,621 | $ 14,670 |
FV Measurements (Hybrid Notes)
FV Measurements (Hybrid Notes) (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | $ 1,200 | $ 1,100 |
Net investment in United States dollar denominated operations | ||
Hybrid Instruments [Line Items] | ||
Hybrid Notes as a hedge of the foreign currency exposure | 1,200 | |
After-tax foreign currency gain (loss) | $ 38 | $ (97) |
Related Paty Transactions (Narr
Related Paty Transactions (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
NSPML | Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 163 | $ 157 |
M&NP | Non-Regulated | ||
Related Party Transaction [Line Items] | ||
Purchases from Related Party | $ 14 | $ 9 |
Receivables and Other Current_3
Receivables and Other Current Assets (Summary of Receivables and Other Current Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Receivables and Other Current Assets [Abstract] | ||
Customer accounts receivable - billed | $ 805 | $ 1,096 |
Capitalized transportation capacity | 358 | 781 |
Customer accounts receivable - unbilled | 363 | 424 |
Prepaid expenses | 105 | 82 |
Income taxes receivable | 10 | 9 |
Allowance for credit losses | (15) | (17) |
NMGC gas hedge settlement receivable | 162 | |
Other | 191 | 360 |
Total receivables and other current assets | $ 1,817 | $ 2,897 |
Leases (Narrative) (Details)
Leases (Narrative) (Details) $ in Millions, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | Oct. 31, 2023 USD ($) | |
Lessee, Operating Leases | |||
Lessee, Operating Lease, Description | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised. | ||
Lease, Expense | $ 127 | $ 138 | |
Variable costs for power generation facility finance leases | $ 119 | 131 | |
Lessee, Operating Lease, Existence of Option to Extend [true false] | true | ||
Lessee, Operating Lease, Option to Extend | The Company has operating leases for buildings, land, telecommunication services, and rail cars. Emera’s leases have remaining lease terms of 1 year to 62 years, some of which include options to extend the leases for up to 65 years. These options are included as part of the lease term when it is considered reasonably certain they will be exercised | ||
Lessee, Lease, Description [Line Items] | |||
Net Investment in Lease | $ 658 | $ 638 | |
Renewable Natural Gas Facility [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lessor, sales-type lease, term of contract | 15 years | ||
Lessor Sales Type Lease Assumptions And Judgments Value Of Underlying Asset Amount | $ 35 | ||
Brunswick Pipeline Lease [Member] | |||
Lessee, Lease, Description [Line Items] | |||
Lessor, operating lease, term of contract | 34 years | ||
Net Investment in Lease | $ 100 | ||
Lessor lease option to extend | 16 years | ||
Minimum | |||
Lessee, Lease, Description [Line Items] | |||
Lessee, operating lease, renewal term | 1 year | ||
Maximum | |||
Lessee, Lease, Description [Line Items] | |||
Lessee, operating lease, renewal term | 62 years |
Leases (Lessee, Operating Lease
Leases (Lessee, Operating Leases and Additional Information) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Assets and Liabilities, Lessee | ||
Right-of-use asset | $ 54 | $ 58 |
Lease liabilities, Current | 3 | 3 |
Lease liabilities, Long-term | 55 | 59 |
Total lease liabilities | 58 | 62 |
Cash paid for amounts included in the measurement of lease liabilities: | ||
Operating cash flows for operating leases | 8 | 8 |
Right-of-use assets obtained in exchange for lease obligations: Operating leases | $ 1 | $ 1 |
Weighted average remaining lease term (years) | 44 years | 44 years |
Weighted average discount rate - operating leases | 3.93% | 3.98% |
Leases (Lessee, Future Minimum
Leases (Lessee, Future Minimum Lease Payments Under Non-Cancellable Operating Leases) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Future minimum lease payments under non-cancellable operating leases for each of the next five years and in aggregate thereafter | ||
2024 | $ 6 | |
2025 | 5 | |
2026 | 3 | |
2027 | 3 | |
2028 | 3 | |
Thereafter | 111 | |
Minimum lease payments, Total | 131 | |
Less imputed interest | (73) | |
Total | $ 58 | $ 62 |
Leases (Lessor, Direct Finance
Leases (Lessor, Direct Finance and Sales-Type Leases) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Net investment in direct finance and sales-type leases | ||
Total minimum lease payments to be received | $ 1,360 | $ 1,393 |
Less: amounts representing estimated executory costs | (190) | (205) |
Minimum lease payments receivable | 1,170 | 1,188 |
Estimated residual value of leased property (unguaranteed) | 183 | 183 |
Less: Credit loss reserve | (2) | 0 |
Less: unearned finance lease income | (693) | (733) |
Net investment in direct finance and sales-type leases | 658 | 638 |
Principal due within one year (included in "Receivables and other current assets") | 37 | 34 |
Net Investment in direct finance leases - long-term | $ 621 | $ 604 |
Leases (Lessor, Future Minimum
Leases (Lessor, Future Minimum Lease Payments to be Received) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
2024 | $ 97 | |
2025 | 99 | |
2026 | 98 | |
2027 | 97 | |
2028 | 96 | |
Thereafter | 873 | |
Total minimum lease payments to be received | 1,360 | $ 1,393 |
Less: executory costs | (190) | (205) |
Minimum lease payments receivable | $ 1,170 | $ 1,188 |
Property, Plant and Equipment_2
Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Property, Plant and Equipment, Net | ||
Total cost | $ 32,273 | $ 30,576 |
Less: Accumulated depreciation | (9,994) | (9,574) |
Total cost less: Accumulated depreciation | 22,279 | 21,002 |
Construction work in progress | 2,097 | 1,994 |
Property, Plant and Equipment, Net | 24,376 | 22,996 |
Generation | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 13,500 | 13,083 |
Generation | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 3 years | |
Generation | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 131 years | |
Transmission | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 2,835 | 2,731 |
Transmission | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 10 years | |
Transmission | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 80 years | |
Distribution | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 7,417 | 6,978 |
Distribution | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 4 years | |
Distribution | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 80 years | |
Gas transmission and distribution | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 5,536 | 5,061 |
Gas transmission and distribution | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 6 years | |
Gas transmission and distribution | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 92 years | |
General plant and other | ||
Property, Plant and Equipment, Net | ||
Total cost | $ 2,985 | $ 2,723 |
General plant and other | Range, Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 2 years | |
General plant and other | Range, Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Estimated useful life | 71 years |
Property, Plant and Equipment_3
Property, Plant and Equipment (Regulated and Non-Regulated Assets) (Narrative) (Details) - Pipeline lateral - SeaCoast Gas Transmission, LLC - General plant and other $ in Millions | 12 Months Ended | |
Dec. 31, 2023 USD ($) mi | Dec. 31, 2022 USD ($) | |
Jointly Owned Pipleline lateral | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50% | 50% |
Length of pipeline, in miles | mi | 26 | |
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service | $ 27 | $ 27 |
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation | $ 2 | $ 1 |
Employee Benefit Plans (Changes
Employee Benefit Plans (Changes in Benefit Obligation and Plan Assets and Funded Status) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined benefit pension plans | ||
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") | ||
Benefit Obligation, Beginning Balance | $ 2,158 | $ 2,624 |
Service cost | 30 | 41 |
Plan participant contributions | 6 | 6 |
Interest cost | 111 | 80 |
Plan amendments | 0 | 0 |
Benefits Paid | (147) | (174) |
Actuarial losses (gains) | 146 | (480) |
Settlements and curtailments | (8) | (6) |
Foreign currency translation adjustment | (23) | 67 |
Benefit Obligation, Ending Balance | 2,273 | 2,158 |
Change in plan assets | ||
Plan Assets, Beginning Balance | 2,163 | 2,702 |
Employer contributions | 42 | 45 |
Plan participant contributions | 6 | 6 |
Benefits paid | (147) | (174) |
Actual return on assets, net of expenses | 262 | (489) |
Settlements and curtailments | (8) | (6) |
FX translation adjustment | (20) | 79 |
Plan Assets, Ending Balance | 2,298 | 2,163 |
Funded Status | ||
Funded status, end of year | 25 | 5 |
Non-pension Benefit Plans | ||
Change in Projected Benefit Obligation ("PBO") and Accumulated Post-retirement Benefit Obligation ("APBO") | ||
Benefit Obligation, Beginning Balance | 243 | 318 |
Service cost | 3 | 4 |
Plan participant contributions | 6 | 6 |
Interest cost | 13 | 9 |
Plan amendments | (14) | 0 |
Benefits Paid | (29) | (31) |
Actuarial losses (gains) | 10 | (79) |
Settlements and curtailments | 0 | 0 |
Foreign currency translation adjustment | (5) | 16 |
Benefit Obligation, Ending Balance | 227 | 243 |
Change in plan assets | ||
Plan Assets, Beginning Balance | 46 | 51 |
Employer contributions | 23 | 24 |
Plan participant contributions | 6 | 6 |
Benefits paid | (29) | (31) |
Actual return on assets, net of expenses | 3 | (7) |
Settlements and curtailments | 0 | 0 |
FX translation adjustment | (1) | 3 |
Plan Assets, Ending Balance | 48 | 46 |
Funded Status | ||
Funded status, end of year | $ (179) | $ (197) |
Employee Benefit Plans (Plans w
Employee Benefit Plans (Plans with PBO/APBO in Excess of Plan Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Defined benefit pension plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | $ 120 | $ 1,006 |
FV of plan assets | 37 | 914 |
Funded Status | (83) | (92) |
Non-pension Benefit Plans | ||
Plans with PBO/APBO in Excess of Plan Assets | ||
PBO/APBO | 205 | 221 |
FV of plan assets | 0 | 0 |
Funded Status | $ (205) | $ (221) |
Employee Benefit Plans (Plans_2
Employee Benefit Plans (Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO for the defined benefit pension plans | $ 2,172 | $ 2,080 |
Defined benefit pension plans | ||
Plans with Accumulated Benefit Obligation ("ABO") in Excess of Plan Assets | ||
ABO | 114 | 111 |
Fair value of plan assets | 37 | 33 |
Funded Status | $ (77) | $ (78) |
Employee Benefit Plans (Amounts
Employee Benefit Plans (Amounts Recognized in Consolidated Balance Sheets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Balance Sheet | ||
Other current liabilities | $ (23) | $ (33) |
Long-term liabilities | (265) | (281) |
Defined benefit pension plans | ||
Balance Sheet | ||
Other current liabilities | (5) | (13) |
Long-term liabilities | (78) | (80) |
Other long-term assets | 108 | 98 |
AOCI, net of tax and regulatory assets | 385 | 358 |
Less: Deferred income tax (expense) recovery in AOCI | (8) | (7) |
Net amount recognized | 402 | 356 |
Non-pension Benefit Plans | ||
Balance Sheet | ||
Other current liabilities | (18) | (20) |
Long-term liabilities | (187) | (201) |
Other long-term assets | 26 | 24 |
AOCI, net of tax and regulatory assets | 20 | 22 |
Less: Deferred income tax (expense) recovery in AOCI | (1) | (1) |
Net amount recognized | $ (160) | $ (176) |
Employee Benefit Plans (Amoun_2
Employee Benefit Plans (Amounts Recognized in AOCI and Regulatory Assets) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Change in AOCI and Regulatory Assets | ||
Regulatory assets | $ 3,105 | $ 3,620 |
Defined benefit pension plans | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 22 | |
Amortized in current period | 1 | 8 |
Ending Balance | 61 | 22 |
Actuarial losses | 53 | 15 |
Past service gains | 0 | 0 |
Deferred income tax expense (recovery) | 8 | 7 |
AOCI, net of tax | 61 | 22 |
Regulatory assets | 324 | 336 |
AOCI, net of tax and regulatory assets | 385 | 358 |
Defined benefit pension plans | Regulatory | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 336 | |
Amortized in current period | (6) | |
Current year additions (reductions) | 1 | |
Change in FX rate | (7) | |
Ending Balance | 324 | 336 |
Defined benefit pension plans | Actuarial (gains) losses | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 15 | |
Amortized in current period | (3) | |
Current year additions (reductions) | 41 | |
Change in FX rate | 0 | |
Ending Balance | 53 | 15 |
Defined benefit pension plans | Past service costs (gains) | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 0 | |
Amortized in current period | 0 | |
Current year additions (reductions) | 0 | |
Change in FX rate | 0 | |
Ending Balance | 0 | 0 |
Non-pension Benefit Plans | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | (9) | |
Amortized in current period | (3) | 0 |
Ending Balance | (9) | (9) |
Actuarial losses | (8) | (10) |
Past service gains | (2) | 0 |
Deferred income tax expense (recovery) | 1 | 1 |
AOCI, net of tax | (9) | (9) |
Regulatory assets | 29 | 31 |
AOCI, net of tax and regulatory assets | 20 | 22 |
Non-pension Benefit Plans | Regulatory | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 31 | |
Amortized in current period | 2 | |
Current year additions (reductions) | (3) | |
Change in FX rate | (1) | |
Ending Balance | 29 | 31 |
Non-pension Benefit Plans | Actuarial (gains) losses | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | (10) | |
Amortized in current period | 3 | |
Current year additions (reductions) | (1) | |
Change in FX rate | 0 | |
Ending Balance | (8) | (10) |
Non-pension Benefit Plans | Actuarial (gains) losses | Assets | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 0 | |
Amortized in current period | 0 | |
Current year additions (reductions) | (3) | |
Change in FX rate | 1 | |
Ending Balance | (2) | 0 |
Non-pension Benefit Plans | Past service costs (gains) | ||
Change in AOCI and Regulatory Assets | ||
Beginning Balance | 0 | |
Amortized in current period | 0 | |
Current year additions (reductions) | (3) | |
Change in FX rate | 1 | |
Ending Balance | $ (2) | $ 0 |
Employee Benefit Plans (Net Per
Employee Benefit Plans (Net Periodic Benefit Cost) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined Benefit Plan Disclosure [Line Items] | ||
Expected return on plan assets | $ (2,577) | $ (2,482) |
Defined benefit pension plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 30 | 41 |
Interest cost | 111 | 80 |
Expected return on plan assets | (161) | (144) |
Current year amortization of: Actuarial losses | 1 | 8 |
Regulatory assets (liability) | 6 | 21 |
Settlement, curtailments | 2 | 2 |
Net Periodic Benefit Cost, Total | (11) | 8 |
Non-pension Benefit Plans | ||
Defined Benefit Plan Disclosure [Line Items] | ||
Service cost | 3 | 4 |
Interest cost | 13 | 9 |
Expected return on plan assets | (2) | 0 |
Current year amortization of: Actuarial losses | (3) | 0 |
Regulatory assets (liability) | (2) | 2 |
Settlement, curtailments | 0 | 0 |
Net Periodic Benefit Cost, Total | $ 9 | $ 15 |
Employee Benefit Plans (Pension
Employee Benefit Plans (Pension Plan Asset Allocations) (Details) - Defined benefit pension plans | Dec. 31, 2023 |
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 0% |
Cash and cash equivalents | Non-Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 10% |
Short-term securities | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 0% |
Short-term securities | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 10% |
Fixed income | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 34% |
Fixed income | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 49% |
Fixed income | Non-Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 29% |
Fixed income | Non-Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 49% |
Equities: Canadian | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 7% |
Equities: Canadian | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 17% |
Equities: Non-Canadian | Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 35% |
Equities: Non-Canadian | Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 59% |
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Minimum | |
Pension Plan Asset Allocations | |
Target Range at Market | 48% |
Equities: Non-Canadian | Non-Canadian Pension Plans | Range, Maximum | |
Pension Plan Asset Allocations | |
Target Range at Market | 68% |
Employee Benefit Plans (Fair Va
Employee Benefit Plans (Fair Value of Plan Assets) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 |
Defined benefit pension plans | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 2,298 | $ 2,163 | $ 2,702 |
Total | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 2,298 | $ 2,163 | |
Percentage | 100% | 100% | |
Total | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 40 | $ 70 | |
Percentage | 2% | 3% | |
Total | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ (9) | $ (70) | |
Percentage | 0% | (3.00%) | |
Total | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 96 | $ 87 | |
Percentage | 4% | 4% | |
Total | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 141 | $ 233 | |
Percentage | 6% | 11% | |
Total | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 112 | $ 186 | |
Percentage | 5% | 8% | |
Total | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 172 | $ 104 | |
Percentage | 8% | 5% | |
Total | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 90 | $ 83 | |
Percentage | 4% | 4% | |
Total | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 9 | $ 14 | |
Percentage | 0% | 1% | |
Total | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 50 | $ 68 | |
Percentage | 2% | 3% | |
Total | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 5 | $ (3) | |
Percentage | 0% | 0% | |
Total | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 1,006 | $ 790 | |
Percentage | 44% | 36% | |
Total | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 586 | $ 601 | |
Percentage | 25% | 28% | |
NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 1,592 | $ 1,391 | |
NAV | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
NAV | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 1,006 | 790 | |
NAV | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 586 | 601 | |
Level 1 | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 440 | 577 | |
Level 1 | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 40 | 70 | |
Level 1 | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | (9) | (70) | |
Level 1 | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 96 | 87 | |
Level 1 | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 141 | 233 | |
Level 1 | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 112 | 186 | |
Level 1 | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 4 | 3 | |
Level 1 | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 50 | 68 | |
Level 1 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 6 | 0 | |
Level 1 | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 1 | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 266 | 195 | |
Level 2 | Cash and cash equivalents | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Net in-transits | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Canadian equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | US equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Other equity | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Government | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 172 | 104 | |
Level 2 | Corporate | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 90 | 83 | |
Level 2 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 5 | 11 | |
Level 2 | Mutual funds | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Other | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | (1) | (3) | |
Level 2 | Open-ended investments measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | 0 | 0 | |
Level 2 | Common collective trusts measured at NAV | |||
Classification of the methodology used by the Company to fair value its investments | |||
Fair Value of Plan Assets | $ 0 | $ 0 |
Employee Benefit Plans (Expecte
Employee Benefit Plans (Expected Cash Flows for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details) $ in Millions | Dec. 31, 2023 CAD ($) |
Defined benefit pension plans | |
Expected employer contributions | |
Expected employer contributions, 2024 | $ 34 |
Expected benefit payments | |
Expected benefit payments, 2024 | 172 |
Expected benefit payments, 2025 | 163 |
Expected benefit payments, 2026 | 166 |
Expected benefit payments, 2027 | 171 |
Expected benefit payments, 2028 | 173 |
Expected benefit payments, 2029 - 2033 | 890 |
Non-pension Benefit Plans | |
Expected employer contributions | |
Expected employer contributions, 2024 | 19 |
Expected benefit payments | |
Expected benefit payments, 2024 | 21 |
Expected benefit payments, 2025 | 21 |
Expected benefit payments, 2026 | 21 |
Expected benefit payments, 2027 | 21 |
Expected benefit payments, 2028 | 20 |
Expected benefit payments, 2029 - 2033 | $ 95 |
Employee Benefit Plans (Assumpt
Employee Benefit Plans (Assumptions Used in Accounting for Defined Benefit Pension and Other Post-Retirement Benefit Plans) (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined benefit pension plans | ||
Benefit obligation - December 31: | ||
Discount rate - past service | 4.89% | 5.33% |
Discount rate - future service | 4.88% | 5.34% |
Rate of compensation increase | 3.87% | 3.62% |
Health care trend - initial (next year) | 0% | 0% |
Health care trend - ultimate | 0% | 0% |
Benefit cost for year ended December 31: | ||
Discount rate - past service | 5.33% | 3.05% |
Discount rate - future service | 5.34% | 3.18% |
Expected long-term return on plan assets | 6.56% | 6.07% |
Rate of compensation increase | 3.62% | 3.31% |
Health care trend - initial (next year) | 0% | 0% |
Health care trend - ultimate | 0% | 0% |
Non-pension Benefit Plans | ||
Benefit obligation - December 31: | ||
Discount rate - past service | 4.89% | 5.31% |
Discount rate - future service | 4.89% | 5.32% |
Rate of compensation increase | 3.85% | 3.61% |
Health care trend - initial (next year) | 6.04% | 5.40% |
Health care trend - ultimate | 3.76% | 3.77% |
Health care trend - year ultimate reached | 2043 | 2043 |
Benefit cost for year ended December 31: | ||
Discount rate - past service | 5.31% | 2.81% |
Discount rate - future service | 5.32% | 2.92% |
Expected long-term return on plan assets | 2.16% | 1.32% |
Rate of compensation increase | 3.61% | 3.29% |
Health care trend - initial (next year) | 5.40% | 5.09% |
Health care trend - ultimate | 3.77% | 3.77% |
Health care trend - year ultimate reached | 2043 | 2042 |
Employee Benefit Plans (Narrati
Employee Benefit Plans (Narrative) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Description | Emera maintains a number of contributory defined-benefit (“DB”) and defined-contribution (“DC”) pension plans, which cover substantially all of its employees. In addition, the Company provides non-pension benefits for its retirees. These plans cover employees in Nova Scotia, New Brunswick, Newfoundland and Labrador, Florida, New Mexico, Barbados, and Grand Bahama Island. | |
Defined Benefit Plan, Plan Assets, Investment Policy and Strategy, Description | The market-related value of assets is based on a five-year smoothed asset value. Any investment gains (or losses) in excess of (or less than) the expected return on plan assets are recognized on a straight-line basis into the market-related value of assets over a five-year period. | |
Defined Benefit Plan, Plan Assets, Expected Long-term Rate-of-Return, Description | The expected long-term rate of return on plan assets is based on historical and projected real rates of return for the plan’s current asset allocation, and assumed inflation. A real rate of return is determined for each asset class. Based on the asset allocation, an overall expected real rate of return for all assets is determined. The asset return assumption is equal to the overall real rate of return assumption added to the inflation assumption, adjusted for assumed expenses to be paid from the plan. | |
Defined Benefit Plan, Expected Return on Plan Assets | $ 2,577 | $ 2,482 |
Contribution Amount | $ 45 | 41 |
Plan assets recognition period | 5 years | |
Defined benefit pension plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 161 | 144 |
Non-pension Benefit Plans | ||
Defined-Benefit Plans, information | ||
Defined Benefit Plan, Expected Return on Plan Assets | $ 2 | $ 0 |
Goodwill (Change in Goodwill) (
Goodwill (Change in Goodwill) (Details) | 12 Months Ended | ||
Dec. 31, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | |
Goodwill [Roll Forward] | |||
Balance, January 1 | $ 6,012,000,000 | $ 5,696,000,000 | |
Change in FX rate | (141,000,000) | 389,000,000 | |
GBPC impairment charge | 0 | (73,000,000) | |
Balance, December 31 | 5,871,000,000 | 6,012,000,000 | |
Tampa Electric and PGS | |||
Goodwill [Roll Forward] | |||
GBPC impairment charge | $ 0 | ||
NMGC | |||
Goodwill [Roll Forward] | |||
GBPC impairment charge | $ 0 | ||
GBPC | |||
Goodwill [Roll Forward] | |||
Balance, January 1 | |||
GBPC impairment charge | $ (73,000,000) | ||
Balance, December 31 |
Short-Term Debt (Short-Term Deb
Short-Term Debt (Short-Term Debt and Related Weighted-Average Interest Rates) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 1,433 | $ 2,726 |
Weighted average interest rate | 5.95% | 5.01% |
Advances on revolving credit and term facilities | TECO Finance | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 245 | $ 481 |
Weighted average interest rate | 6.54% | 5.47% |
Non-revolving term facilities | Emera Inc. | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 796 | $ 796 |
Weighted average interest rate | 6.07% | 5.19% |
Bank indebtedness | Emera Inc. | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 9 | $ 0 |
Weighted average interest rate | 0% | 0% |
Advances on revolving credit facilities | TEC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 277 | $ 1,380 |
Weighted average interest rate | 5.68% | 5% |
Advances on revolving credit facilities | PGS | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 73 | $ 0 |
Weighted average interest rate | 6.36% | 0% |
Advances on revolving credit facilities | NMGC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 25 | $ 59 |
Weighted average interest rate | 6.46% | 5.15% |
Advances on revolving credit facilities | GBPC | ||
Short-term debt and the related weighted-average interest rates | ||
Short-term debt | $ 8 | $ 10 |
Weighted average interest rate | 5.54% | 5.25% |
Short-Term Debt (Short-Term Rev
Short-Term Debt (Short-Term Revolving and Non-Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Total available capacity | $ 2,773 | $ 3,155 |
Total advances under available facilities | 1,436 | 2,735 |
Available capacity under existing agreements | $ 1,337 | 420 |
Revolving credit facility | TEC | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2026 | |
Total available capacity | $ 401 | 1,084 |
Revolving credit facility | TECO Energy/TECO Finance | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2026 | |
Total available capacity | $ 0 | 542 |
Revolving credit facility | TECO Finance | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2026 | |
Total available capacity | $ 529 | 0 |
Revolving credit facility | PGS | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2028 | |
Total available capacity | $ 331 | 0 |
Revolving credit facility | NMGC | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2026 | |
Total available capacity | $ 165 | 169 |
Revolving credit facility II | TEC | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2024 | |
Total available capacity | $ 265 | 542 |
Revolving credit facility III | TEC | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2024 | |
Total available capacity | $ 265 | 0 |
Revolving credit facility III | Other | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Total available capacity | $ 17 | 18 |
Term credit facility | TEC | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2024 | |
Non-revolving term loan | Emera Inc. | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2024 | |
Total available capacity | $ 400 | 400 |
Non-revolving term loan II | Emera Inc. | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Maturity | 2024 | |
Total available capacity | $ 400 | 400 |
Advances under revolving credit and term facilities | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Total advances under available facilities | 1,433 | 2,731 |
Letters of credit issued within the credit facilities | ||
Short-term revolving and non-revolving credit facilities, outstanding borrowings and available capacity | ||
Total advances under available facilities | $ 3 | $ 4 |
Short-Term Debt (Narrative) (De
Short-Term Debt (Narrative) (Details) $ in Millions, $ in Millions | Dec. 16, 2023 CAD ($) | Dec. 15, 2023 | Dec. 01, 2023 USD ($) | Nov. 24, 2023 USD ($) | Jun. 30, 2023 CAD ($) | Jun. 29, 2023 | Apr. 03, 2023 USD ($) | Mar. 01, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) |
Line of Credit Facility [Line Items] | ||||||||||
Weighted average interest rate | 5.95% | 5.01% | ||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 2,773 | $ 3,155 | ||||||||
Revolving credit facility | TEC | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 401 | 1,084 | ||||||||
Revolving credit facility | NMGC | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 165 | 169 | ||||||||
Revolving credit facility | TECO Energy/TECO Finance | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 0 | 542 | ||||||||
Revolving credit facility | TECO Finance | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 529 | 0 | ||||||||
Revolving credit facility | Peoples Gas System [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 331 | 0 | ||||||||
Revolving credit facility | Peoples Gas System [Member] | Gas Utilities and Infrastructure | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 250 | |||||||||
Line of Credit Facility, Expiration Date | Dec. 01, 2028 | |||||||||
Available increase in borrowing capacity | $ 100 | |||||||||
Revolving credit facility II | TEC | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | 265 | 542 | ||||||||
Revolving credit facility II | TEC | Florida Electric Utility [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200 | |||||||||
Line of Credit Facility, Expiration Date | Apr. 01, 2024 | |||||||||
Debt term | 364 days | |||||||||
Revolving credit facility III | TEC | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 265 | $ 0 | ||||||||
Revolving credit facility III | TEC | Florida Electric Utility [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 200 | |||||||||
Line of Credit Facility, Expiration Date | Feb. 28, 2024 | |||||||||
Debt term | 364 days | |||||||||
Non-revolving term facilities | TEC | Florida Electric Utility [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | |||||||||
Line of Credit Facility, Expiration Date | Dec. 13, 2023 | |||||||||
Non-revolving term facilities | Emera Inc. | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Weighted average interest rate | 6.07% | 5.19% | ||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | $ 400 | ||||||||
Non-revolving term facilities | Emera Inc. | Other Segments [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | |||||||||
Debt Instrument, Maturity Date | Dec. 16, 2024 | Dec. 16, 2023 | ||||||||
Non-revolving term loan II | Emera Inc. | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | $ 400 | ||||||||
Non-revolving term loan II | Emera Inc. | Other Segments [Member] | ||||||||||
Line of Credit Facility [Line Items] | ||||||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 400 | |||||||||
Debt Instrument, Maturity Date | Aug. 02, 2024 | Aug. 02, 2023 |
Other Current Liabilities (Comp
Other Current Liabilities (Components of Other Current Liabilities) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Other Current Liabilities | ||
Accrued charges | $ 172 | $ 174 |
Nova Scotia Cap-and-Trade Program provision | 0 | 172 |
Accrued interest on long-term debt | 107 | 97 |
Pension and post-retirement liabilities | 23 | 33 |
Sales and other taxes payable | 11 | 14 |
Income taxes payable | 2 | 9 |
Other | 112 | 80 |
Other current liabilities, Total | $ 427 | $ 579 |
Long-Term Debt (Summary of Long
Long-Term Debt (Summary of Long-Term Debt, Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Debt Instrument [Line Items] | ||
Debt issuance costs | $ (125) | $ (126) |
Amount due within one year | (676) | (574) |
Long Term Debt, Adjustments | (801) | (698) |
Long-Term Debt | 17,689 | 15,744 |
Interest expense | 109 | 110 |
Emera | ||
Debt Instrument [Line Items] | ||
Long-term debt | 2,552 | 2,528 |
NMGC | ||
Debt Instrument [Line Items] | ||
Long-term debt | 672 | 629 |
NSPI | ||
Debt Instrument [Line Items] | ||
Long-term debt | 3,886 | 3,546 |
ECI | ||
Debt Instrument [Line Items] | ||
Long-term debt | 422 | 449 |
TECO Energy | ||
Debt Instrument [Line Items] | ||
Fair market value adjustment | $ 0 | $ 2 |
Bankers acceptances | SOFR loans | Emera | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2027 | |
Long-term debt | $ 465 | $ 403 |
Unsecured fixed rate notes | Emera | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 4.84% | 2.90% |
Maturity | 2030 | |
Long-term debt | $ 500 | $ 500 |
Unsecured fixed rate notes | Emera Finance | ||
Debt Instrument [Line Items] | ||
Maturity | 2024 - 2046 | |
Fixed to floating subordinated notes | Emera | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 6.75% | 6.75% |
Maturity | 2076 | |
Long-term debt | $ 1,587 | $ 1,625 |
Unsecured senior notes | Emera Finance | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 3.65% | 3.65% |
Long-term debt | $ 3,637 | $ 3,725 |
Fixed rate notes and bonds | TEC | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 4.61% | 4.15% |
Maturity | 2024 - 2051 | |
Long-term debt | $ 5,654 | $ 4,341 |
Fixed rate notes and bonds | PGS | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 5.63% | 3.78% |
Maturity | 2028 - 2053 | |
Long-term debt | $ 1,223 | $ 772 |
Fixed rate notes and bonds | NMGC | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 3.78% | 3.11% |
Maturity | 2026 - 2051 | |
Long-term debt | $ 642 | $ 521 |
Fixed rate notes and bonds | NMGI | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 3.64% | 3.64% |
Maturity | 2024 | |
Long-term debt | $ 198 | $ 203 |
Discount notes | NSPI | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2024 - 2027 | |
Long-term debt | $ 721 | $ 881 |
Medium term fixed rate notes | NSPI | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 5.13% | 5.14% |
Maturity | 2025 - 2097 | |
Long-term debt | $ 3,165 | $ 2,665 |
Senior secured credit facility | EBP | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2026 | |
Long-term debt | $ 246 | $ 249 |
Amortizing fixed rate notes | ECI | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 4% | 3.97% |
Maturity | 2026 | |
Long-term debt | $ 79 | $ 100 |
Secured senior notes | ECI | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2027 | |
Long-term debt | $ 75 | $ 86 |
Secured fixed rate senior notes | ECI | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 3.09% | 3.06% |
Maturity | 2024 - 2029 | |
Long-term debt | $ 84 | $ 142 |
Non-revolving term facility, floating rate | NMGC | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2024 | |
Long-term debt | $ 30 | $ 108 |
Non-revolving term facility, floating rate | ECI | ||
Debt Instrument [Line Items] | ||
Interest Rate Terms | Variable | Variable |
Maturity | 2025 | |
Long-term debt | $ 29 | $ 30 |
Non-revolving term facility, fixed rate | ECI | ||
Debt Instrument [Line Items] | ||
Weighted average interest rate | 2.15% | 2.05% |
Maturity | 2025 - 2027 | |
Long-term debt | $ 155 | $ 91 |
Long-Term Debt (Revolving Credi
Long-Term Debt (Revolving Credit Facilities, Outstanding Borrowings and Available Capacity) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 2,773 | $ 3,155 |
Use of available facilities | 1,890 | 1,408 |
Available capacity under existing agreements | 1,337 | 420 |
Revolving credit facility | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | 3,197 | 2,219 |
Available capacity under existing agreements | 1,307 | 811 |
Advances on the revolving credit facility | 50 | |
Revolving credit facility | Emera | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 900 | 900 |
Maturity | June 2027 | |
Revolving credit facility | TEC | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 657 | 0 |
Maturity | December 2026 | |
Revolving credit facility | NSPI | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 800 | 800 |
Maturity | December 2027 | |
Revolving credit facility | ECI | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 10 | 11 |
Maturity | October 2024 | |
Non-revolving credit facility | Emera | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 400 | 0 |
Maturity | February 2024 | |
Non-revolving credit facility | NSPI | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 400 | 400 |
Maturity | July 2024 | |
Non-revolving credit facility | NMGC | ||
Debt Instrument [Line Items] | ||
Available capacity under existing agreements | $ 30 | 108 |
Maturity | March 2024 | |
Borrowings under credit facilities | ||
Debt Instrument [Line Items] | ||
Use of available facilities | $ 1,884 | 1,396 |
Letters of credit issued within the credit facilities | ||
Debt Instrument [Line Items] | ||
Use of available facilities | $ 6 | $ 12 |
Long-Term Debt (Significant Cov
Long-Term Debt (Significant Covenants) (Details) | Dec. 31, 2023 |
Maximum | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.70 |
Syndicated credit facilities | |
Debt Instrument [Line Items] | |
Debt to capital ratio | 0.57 |
Long-Term Debt (Long-Term Debt
Long-Term Debt (Long-Term Debt Maturities) (Details) $ in Millions | Dec. 31, 2023 CAD ($) |
Subsidiaries | |
Debt Instrument [Line Items] | |
2024 | $ 1,670 |
2025 | 264 |
2026 | 3,047 |
2027 | 666 |
2028 | 525 |
Thereafter | 12,318 |
Total, long-term debt maturities, including capital lease obligations | 18,490 |
Emera | |
Debt Instrument [Line Items] | |
2024 | 199 |
2025 | 0 |
2026 | 1,587 |
2027 | 266 |
2028 | 0 |
Thereafter | 500 |
Total, long-term debt maturities, including capital lease obligations | 2,552 |
Emera US Finance LP | |
Debt Instrument [Line Items] | |
2024 | 397 |
2025 | 0 |
2026 | 992 |
2027 | 0 |
2028 | 0 |
Thereafter | 2,248 |
Total, long-term debt maturities, including capital lease obligations | 3,637 |
Tampa Electric | |
Debt Instrument [Line Items] | |
2024 | 397 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
2028 | 0 |
Thereafter | 5,257 |
Total, long-term debt maturities, including capital lease obligations | 5,654 |
PGS | |
Debt Instrument [Line Items] | |
2024 | 0 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
2028 | 463 |
Thereafter | 760 |
Total, long-term debt maturities, including capital lease obligations | 1,223 |
NMGC | |
Debt Instrument [Line Items] | |
2024 | 30 |
2025 | 0 |
2026 | 93 |
2027 | 0 |
2028 | 0 |
Thereafter | 549 |
Total, long-term debt maturities, including capital lease obligations | 672 |
NMGI | |
Debt Instrument [Line Items] | |
2024 | 198 |
2025 | 0 |
2026 | 0 |
2027 | 0 |
2028 | 0 |
Thereafter | 0 |
Total, long-term debt maturities, including capital lease obligations | 198 |
NSPI | |
Debt Instrument [Line Items] | |
2024 | 398 |
2025 | 125 |
2026 | 40 |
2027 | 323 |
2028 | 0 |
Thereafter | 3,000 |
Total, long-term debt maturities, including capital lease obligations | 3,886 |
EBP | |
Debt Instrument [Line Items] | |
2024 | 0 |
2025 | 0 |
2026 | 246 |
2027 | 0 |
2028 | 0 |
Thereafter | 0 |
Total, long-term debt maturities, including capital lease obligations | 246 |
ECI | |
Debt Instrument [Line Items] | |
2024 | 51 |
2025 | 139 |
2026 | 89 |
2027 | 77 |
2028 | 62 |
Thereafter | 4 |
Total, long-term debt maturities, including capital lease obligations | $ 422 |
Long-Term Debt (Narrative) (Det
Long-Term Debt (Narrative) (Details) $ in Millions, $ in Millions | 12 Months Ended | |||||||||
Feb. 16, 2024 | Jan. 30, 2024 USD ($) | Dec. 19, 2023 USD ($) | Oct. 19, 2023 USD ($) | Aug. 18, 2023 CAD ($) | May 24, 2023 USD ($) | May 02, 2023 CAD ($) | Mar. 24, 2023 CAD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 CAD ($) | |
Debt Instrument [Line Items] | ||||||||||
Available capacity under existing agreements | $ 2,773 | $ 3,155 | ||||||||
Repayment of long-term debt | $ 151 | $ 367 | ||||||||
Senior unsecured bonds due March 1, 2029 | TEC | Subsequent event | Florida Electric Utility [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 500 | |||||||||
Maturity date | Mar. 01, 2029 | |||||||||
Stated interest rate | 4.90% | |||||||||
5-year credit facility | TEC | Subsequent event | Florida Electric Utility [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Repayment of long-term debt | $ 497 | |||||||||
Debt term | 5 years | |||||||||
Unsecured notes due November 15, 2032 and March 24, 2053 | NSPI | Canadian Electric Utilities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 500 | |||||||||
Unsecured notes due November 15, 2032 | NSPI | Canadian Electric Utilities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 300 | |||||||||
Maturity date | Nov. 15, 2032 | |||||||||
Stated interest rate | 4.95% | |||||||||
Unsecured notes due March 24, 2053 | NSPI | Canadian Electric Utilities | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 200 | |||||||||
Maturity date | Mar. 24, 2053 | |||||||||
Stated interest rate | 5.36% | |||||||||
Senior notes due December 19, 2028, December 19, 2033 and December 19, 2053 | PGS | Gas Utilities and Infrastructure [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 925 | |||||||||
Senior notes due December 19, 2028 | PGS | Gas Utilities and Infrastructure [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 350 | |||||||||
Maturity date | Dec. 19, 2028 | |||||||||
Stated interest rate | 5.42% | |||||||||
Senior notes due December 19, 2033 | PGS | Gas Utilities and Infrastructure [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 350 | |||||||||
Maturity date | Dec. 19, 2033 | |||||||||
Stated interest rate | 5.63% | |||||||||
Senior notes due December 19, 2053 | PGS | Gas Utilities and Infrastructure [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 225 | |||||||||
Maturity date | Dec. 19, 2053 | |||||||||
Stated interest rate | 5.94% | |||||||||
Senior unsecured notes due October 19, 2033 | NMGC | Gas Utilities and Infrastructure [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 100 | |||||||||
Maturity date | Oct. 19, 2033 | |||||||||
Stated interest rate | 6.36% | |||||||||
Non-revolving term loan due May 24, 2028 | GBPC | Other Electric Utilities [Member] | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 28 | |||||||||
Maturity date | May 24, 2028 | |||||||||
Stated interest rate | 4% | |||||||||
Non-revolving term facility due February 19, 2025 | Emera | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 400 | |||||||||
Maturity date | Feb. 19, 2024 | |||||||||
Non-revolving term facility due February 19, 2025 | Emera | Subsequent event | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Maturity date | Feb. 19, 2025 | |||||||||
Senior unsecured notes due May 2, 2030 | Emera | ||||||||||
Debt Instrument [Line Items] | ||||||||||
Debt instrument, face amount | $ 500 | |||||||||
Maturity date | May 02, 2030 | |||||||||
Stated interest rate | 4.84% |
Asset Retirement Obligation (Ch
Asset Retirement Obligation (Change in Asset Retirement Obligations) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Change in ARO | ||
Balance, January 1 | $ 174 | $ 174 |
Accretion included in depreciation expense | 9 | 9 |
Change in FX rate | (1) | 3 |
Additions | 0 | 1 |
Accretion deferred to regulatory asset (included in PP&E) | 18 | 1 |
Liabilities settled | (8) | (1) |
Revisions in estimated cash flows | 0 | (13) |
Balance, December 31 | $ 192 | $ 174 |
Commitments and Contingencies_2
Commitments and Contingencies (Summary of Contractual Commitments) (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 CAD ($) MW | Dec. 31, 2022 CAD ($) | |
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | $ 2,698 | |
2025 | 1,217 | |
2026 | 856 | |
2027 | 747 | |
2028 | 690 | |
Thereafter | 6,253 | |
Contractual Commitments | 12,461 | |
Other commitments | ||
Commitment | 1,772 | $ 2,273 |
Revenue, Remaining Performance Obligation, Amount | $ 488 | $ 450 |
Nalcor Energy | ||
Other commitments | ||
Long-term Purchase Commitment, Period | 50 years | |
Nalcor Energy | Equity contributions true ups | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
Contractual Commitments | $ 240 | |
SeaCoast Gas Transmission, LLC | PGS | ||
Other commitments | ||
Revenue, Remaining Performance Obligation, Amount | $ 134 | |
Maritime Link Project | ||
Other commitments | ||
Long-term Purchase Commitment, Period | 38 years | |
Maritime Link Project | NSPML | ||
Other commitments | ||
Approved base rate | $ 1,800 | |
Maritime Link Project | NSPI | ||
Other commitments | ||
Commitment | $ 164 | |
LIL | ||
Other commitments | ||
Capacity of electricity transmission project (MW) | MW | 700 | |
Transportation | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | $ 696 | |
2025 | 495 | |
2026 | 405 | |
2027 | 388 | |
2028 | 338 | |
Thereafter | 2,597 | |
Contractual Commitments | 4,919 | |
Purchased power | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | 274 | |
2025 | 249 | |
2026 | 263 | |
2027 | 312 | |
2028 | 312 | |
Thereafter | 3,435 | |
Contractual Commitments | 4,845 | |
Fuel, gas supply and storage | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | 556 | |
2025 | 215 | |
2026 | 62 | |
2027 | 0 | |
2028 | 5 | |
Thereafter | 0 | |
Contractual Commitments | 838 | |
Capital projects | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | 778 | |
2025 | 111 | |
2026 | 70 | |
2027 | 1 | |
2028 | 0 | |
Thereafter | 0 | |
Contractual Commitments | 960 | |
Equity Method Investments | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | 240 | |
2025 | 0 | |
2026 | 0 | |
2027 | 0 | |
2028 | 0 | |
Thereafter | 0 | |
Contractual Commitments | 240 | |
Other Commitment [Member] | ||
Recorded Unconditional Purchase Obligation [Line Items] | ||
2024 | 154 | |
2025 | 147 | |
2026 | 56 | |
2027 | 46 | |
2028 | 35 | |
Thereafter | 221 | |
Contractual Commitments | $ 659 |
Commitments and Contingencies_3
Commitments and Contingencies (Legal Proceedings) (Narrative) (Details) - Dec. 31, 2023 $ in Millions, $ in Millions | CAD ($) | USD ($) |
Prime Rate [Member] | Tampa Electric | ||
Loss Contingencies [Line Items] | ||
Loss Contingency, Estimate of Possible Loss | $ 15 | $ 11 |
Commitments and Contingencies_4
Commitments and Contingencies (Guarantees and Letters of Credit) (Narrative) (Details) $ in Millions, $ in Millions | Dec. 31, 2023 USD ($) | Dec. 31, 2023 CAD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2022 CAD ($) |
Nova Scotia Power Inc. [Member] | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | $ 104 | $ 119 | ||
Letters of Credit Outstanding, Amount | $ 56 | $ 63 | ||
TECO Energy | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 13 | |||
Guarantor Obligations, Maximum Exposure, Undiscounted | 13 | |||
TECO Energy | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Guarantor Obligations, Maximum Exposure, Undiscounted | 45 | |||
ECI | ||||
Guarantor Obligations [Line Items] | ||||
Guaranty Liabilities | 66 | |||
Payment Guarantee | SeaCoast Gas Transmission, LLC | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | 27 | |||
Surety Bonds | ||||
Guarantor Obligations [Line Items] | ||||
Letters of Credit Outstanding, Amount | $ 103 | $ 145 |
Commitments and Contingencies_5
Commitments and Contingencies (Collaborative Arrangements) (Narrative) (Details) - Jointly Owned Electricity Generation Plant - NSPI - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items] | ||
Regulated fuel for generation and purchased power | $ 8 | $ 12 |
Operating, maintenance and general (OM&G) | $ 3 | $ 3 |
Cumulative Preferred Stock (Sum
Cumulative Preferred Stock (Summary of Cumulative Preferred Stock Authorized) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Class of Stock [Line Items] | ||
Issued and Outstanding | 58,000,000 | 58,000,000 |
Net Proceeds | $ 1,422 | $ 1,422 |
Series A Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 0.5456 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 4,866,814 | 4,866,814 |
Net Proceeds | $ 119 | $ 119 |
Series B Preferred Stock | ||
Class of Stock [Line Items] | ||
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 1,133,186 | 1,133,186 |
Net Proceeds | $ 28 | $ 28 |
Preferred Stock Dividend Payment Rate Variable | Floating | |
Series C Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.6085 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 10,000,000 | 10,000,000 |
Net Proceeds | $ 245 | $ 245 |
Series E Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.1250 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 5,000,000 | 5,000,000 |
Net Proceeds | $ 122 | $ 122 |
Series F Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.0505 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 8,000,000 | 8,000,000 |
Net Proceeds | $ 195 | $ 195 |
Series H Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.5810 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 12,000,000 | 12,000,000 |
Net Proceeds | $ 295 | $ 295 |
Series J Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.0625 | |
Preferred Stock, Redemption Price Per Share | $ 25 | |
Issued and Outstanding | 8,000,000 | 8,000,000 |
Net Proceeds | $ 196 | $ 196 |
Series L Preferred Stock | ||
Class of Stock [Line Items] | ||
Annual Dividend Per Share | $ 1.1500 | |
Preferred Stock, Redemption Price Per Share | $ 26 | |
Issued and Outstanding | 9,000,000 | 9,000,000 |
Net Proceeds | $ 222 | $ 222 |
Cumulative Preferred Stock (Cha
Cumulative Preferred Stock (Characteristics of the First Preferred Shares) (Details) - 12 months ended Dec. 31, 2023 - $ / shares | Total | Total |
Series A Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.40% | |
Current Annual Dividend | $ 0.5456 | |
Earliest Redemption and/or Conversion Option Date | August 15, 2025 | August 15, 2025 |
Redemption Value | $ 25 | $ 25 |
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | Right to Convert on a one for one basis |
Conversion of Stock, Type of Stock Converted | Series B | Series B |
Series A Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 1.84% | |
Series C Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.10% | |
Current Annual Dividend | $ 1.6085 | |
Earliest Redemption and/or Conversion Option Date | August 15, 2028 | August 15, 2028 |
Redemption Value | $ 25 | $ 25 |
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | Right to Convert on a one for one basis |
Conversion of Stock, Type of Stock Converted | Series D | Series D |
Series C Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 2.65% | |
Series C Preferred Stock | Prior To August 15, 2028 | ||
Class of Stock [Line Items] | ||
Current Annual Dividend | $ 1.1802 | |
Series F Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.202% | |
Current Annual Dividend | $ 1.0505 | |
Earliest Redemption and/or Conversion Option Date | February 15, 2025 | February 15, 2025 |
Redemption Value | $ 25 | $ 25 |
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | Right to Convert on a one for one basis |
Conversion of Stock, Type of Stock Converted | Series G | Series G |
Series F Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 2.63% | |
Series B Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 2.393% | |
Earliest Redemption and/or Conversion Option Date | August 15, 2025 | August 15, 2025 |
Redemption Value | $ 25 | $ 25 |
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | Right to Convert on a one for one basis |
Conversion of Stock, Type of Stock Converted | Series A | Series A |
Series B Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 1.84% | |
Series H Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.90% | |
Current Annual Dividend | $ 1.5810 | |
Earliest Redemption and/or Conversion Option Date | August 15, 2028 | August 15, 2028 |
Redemption Value | $ 25 | $ 25 |
Preferred Stock, Conversion Basis | Right to Convert on a one for one basis | Right to Convert on a one for one basis |
Conversion of Stock, Type of Stock Converted | Series I | Series I |
Series H Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.90% | |
Series H Preferred Stock | Prior To August 15, 2028 | ||
Class of Stock [Line Items] | ||
Current Annual Dividend | $ 1.2250 | |
Series J Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.25% | |
Current Annual Dividend | $ 1.0625 | |
Earliest Redemption and/or Conversion Option Date | May 15, 2026 | May 15, 2026 |
Redemption Value | $ 25 | $ 25 |
Right to Convert on a one for one basis | Series K | Series K |
Series J Preferred Stock | Minimum | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.25% | |
Series E Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.50% | |
Current Annual Dividend | $ 1.1250 | |
Redemption Value | $ 25 | 25 |
Series L Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 4.60% | |
Current Annual Dividend | $ 1.1500 | |
Earliest Redemption and/or Conversion Option Date | November 15, 2026 | November 15, 2026 |
Redemption Value | $ 26 | $ 26 |
Series L Preferred Stock | On Or After November 15, 2026 to November 15, 2027 | ||
Class of Stock [Line Items] | ||
Redemption Value | 26 | 26 |
Series L Preferred Stock | After November 15, 2027 To November 15, 2030 | ||
Class of Stock [Line Items] | ||
Preferred Stock, Redemption Price, Annual Decrease | 0.25 | 0.25 |
Series L Preferred Stock | After November 15, 2030 | ||
Class of Stock [Line Items] | ||
Redemption Value | 25 | 25 |
Series D Preferred Stock | ||
Class of Stock [Line Items] | ||
Redemption Value | 25 | 25 |
Series D Preferred Stock | After August 15, 2028 | ||
Class of Stock [Line Items] | ||
Redemption Value | 25.50 | 25.50 |
Series G Preferred Stock | ||
Class of Stock [Line Items] | ||
Redemption Value | 25 | 25 |
Series G Preferred Stock | After February 15, 2025 | ||
Class of Stock [Line Items] | ||
Redemption Value | $ 25.5 | 25.5 |
Series I Preferred Stock | ||
Class of Stock [Line Items] | ||
Initial Yield | 2.54% | |
Redemption Value | $ 25 | 25 |
Series I Preferred Stock | After August 15, 2028 | ||
Class of Stock [Line Items] | ||
Redemption Value | $ 25.5 | $ 25.5 |
Cumulative Preferred Stock (Nar
Cumulative Preferred Stock (Narrative) (Details) | 12 Months Ended |
Dec. 31, 2023 | |
First Preferred Shares | |
Class of Stock [Line Items] | |
Preferred Stock Dividend Preference Or Restrictions | First Preferred Shares are neither redeemable at the option of the shareholder nor have a mandatory redemption date. They are classified as equity and the associated dividends are deducted on the Consolidated Statements of Income before arriving at “Net income attributable to common shareholders” and shown on the Consolidated Statement of Changes in Equity as a deduction from retained earnings. The First Preferred Shares of each series rank on a parity with the First Preferred Shares of every other series and are entitled to a preference over the Second Preferred Shares, the Common Shares, and any other shares ranking junior to the First Preferred Shares with respect to the payment of dividends and the distribution of the remaining property and assets or return of capital of the Company in the liquidation, dissolution or wind-up, whether voluntary or involuntary. In the event the Company fails to pay, in aggregate, eight quarterly dividends on any series of the First Preferred Shares, the holders of the First Preferred Shares, for only so long as the dividends remain in arrears, will be entitled to attend any meeting of shareholders of the Company at which directors are to be elected and to vote for the election of two directors out of the total number of directors elected at any such meeting. |
Non-Controlling Interest in S_3
Non-Controlling Interest in Subsidiaries (Components of Non-Controlling Interest) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Noncontrolling Interest [Line Items] | ||
Stockholders' Equity Attributable to Noncontrolling Interest | $ 14 | $ 14 |
GBPC | ||
Noncontrolling Interest [Line Items] | ||
Noncontrolling Interest, Amount Represented by Preferred Stock | $ 14 | $ 14 |
Non-Controlling Interest in S_4
Non-Controlling Interest in Subsidiaries (Preferred Shares of GBPC) (Details) - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Noncontrolling Interest [Line Items] | ||
Number of shares issued and outstanding | 58,000,000 | 58,000,000 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | GBPC | ||
Noncontrolling Interest [Line Items] | ||
Preferred Stock, Shares Authorized | 10,000 | |
Number of shares issued and outstanding | 10,000 | 10,000 |
Outstanding as at December 31 | $ 14 | $ 14 |
Non-Controlling Interest in S_5
Non-Controlling Interest in Subsidiaries (Narrative) (Details) - GBPC | 12 Months Ended |
Dec. 31, 2023 $ / shares | |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Dividend Payment Terms | 6.0 per cent per annum fixed cumulative preferential dividend to be paid semi-annually |
Preferred Stock, Redemption Terms | The preferred shares are redeemable by GBPC after June 17, 2021 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | |
Noncontrolling Interest [Line Items] | |
Preferred Stock, Redemption Price Per Share | $ 1,000 |
Non-voting Cumulative Redeemable Variable Perpetual Preferred Shares | USD preferred shares | |
Noncontrolling Interest [Line Items] | |
Debt Instrument, Interest Rate, Stated Percentage | 6% |
Supplementary Information to _3
Supplementary Information to Consolidated Statements of Cash Flows (Summary of Supplementary Information to Consolidated Statement of Cash Flows) (Details) - CAD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Changes in non-cash working capital | ||
Inventory | $ (31) | $ (214) |
Receivables and other current assets | 653 | (636) |
Accounts payable | (538) | 423 |
Other current liabilities | (179) | 193 |
Total non-cash working capital | (95) | (234) |
Supplemental disclosure of cash paid: | ||
Interest | 930 | 699 |
Income Taxes | 43 | 67 |
Supplemental disclosure of non-cash activities: | ||
Common share dividends reinvested | 271 | 237 |
Reclassification of short-term debt to long-term debt | 657 | 0 |
Reclassification of long-term debt to short-term debt | 0 | 500 |
Decrease in accrued capital expenditures | (19) | (13) |
Supplemental disclosure of operating activities: | ||
Net change in short-term regulatory assets and liabilities | 123 | (157) |
January 2023 Settlement Of NMGC Gas Hedges [Member] | ||
Changes in non-cash working capital | ||
Receivables and other current assets | 162 | (162) |
Nova Scotia Cap-And-Trade Program [Member] | ||
Changes in non-cash working capital | ||
Other current liabilities | $ (166) | $ 172 |
Stock-Based Compensation (Emplo
Stock-Based Compensation (Employee Common Share Purchase Plan and Common Shareholders Dividend Reinvestment and Share Purchase Plan) (Narrative) (Details) shares in Millions | 12 Months Ended | ||
Dec. 31, 2023 CAD ($) shares | Dec. 31, 2023 USD ($) shares | Dec. 31, 2022 CAD ($) | |
Employee Common Share Purchase Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. | Eligible employees may participate in the ECSPP. As of December 31, 2023, the plan allows employees to make cash contributions of a minimum of $25 to a maximum of $20,000 CAD or $15,000 USD per year for the purpose of purchasing common shares of Emera. The Company also contributes 20 per cent of the employees’ contributions to the plan. The plan allows reinvestment of dividends for all participants except where prohibited by law. | |
Defined Contribution Plan, Minimum Annual Contributions Per Employee, Amount | $ 25 | ||
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount | $ 20,000 | $ 15,000 | |
Defined Contribution Plan, Employer Matching Contribution, Percent of Match | 20% | 20% | |
Compensation cost for shares issued | $ 3,000,000 | $ 3,000,000 | |
Dividend Reinvestment Plan | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Employee Common Share Purchase Plan, Description | The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. | The Company also has a Common Shareholders DRIP, which provides an opportunity for shareholders residing in Canada to reinvest dividends and purchase common shares. This plan provides for a discount of up to 5 per cent from the average market price of Emera’s common shares for common shares purchased in connection with the reinvestment of cash dividends. The discount was 2 per cent in 2023. | |
Maximum aggregate number of common shares reserved for issuance | shares | 7 | 7 | |
Discount from Market Price, Purchase Date | 2% | ||
Dividend Reinvestment Plan | Maximum | |||
Employee Stock Ownership Plan (ESOP) Disclosures [Line Items] | |||
Discount from Market Price, Purchase Date | 5% | 5% |
Stock-Based Compensation (Narra
Stock-Based Compensation (Narrative) (Details) $ / shares in Units, $ in Thousands, shares in Millions, $ in Millions | 12 Months Ended | |||
Dec. 31, 2023 CAD ($) $ / shares shares | Dec. 31, 2022 CAD ($) $ / shares shares | Dec. 31, 2022 USD ($) | Dec. 31, 2021 | |
Stock option plan, Additional information | ||||
Percentage of outstanding stock maximum | 10% | |||
Dividend Reinvestment Plan | ||||
Stock option plan, Additional information | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 7 | |||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 7 | |||
DSU Plan | ||||
Share Unit Plans | ||||
Cash payments made during the year | $ 3,000 | $ 8,000 | ||
Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Maximum term | 10 years | |||
Maximum aggregate number of common shares reserved for issuance | shares | 6 | 6 | ||
Terms of award | P10Y | |||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 6 | 6 | ||
Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 2 | 2.7 | ||
Share Unit Plans | ||||
Maximum aggregate number of common shares reserved for issuance | shares | 2 | 2.7 | ||
First Anniversary | DSU Plan | Executive and senior management | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25% | |||
First Anniversary | DSU Plan | Executive and senior management | Minimum | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 50% | |||
Vesting period after date of retirement | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 27 months | |||
Vesting period after termination without just cause or death | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 6 months | 6 months | 6 months | |
Vesting period after termination for just cause or resignation | Employee Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Vesting period | 60 days | 60 days | 60 days | |
Stock Option Plan | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | The Company has a stock option plan that grants options to senior management of the Company for a maximum term of 10 years. The option price of the stock options is the closing price of the Company’s common shares on the Toronto Stock Exchange on the last business day on which such shares were traded before the date on which the option is granted. The maximum aggregate number of shares issuable under this plan is 14.7 million shares. As at December 31, 2023, Emera was in compliance with this requirement. Stock options granted in 2021 and prior vest in 25 per cent increments on the first, second, third and fourth anniversaries of the date of the grant. Stock options granted in 2022 and thereafter vest in 20 per cent increments on the first, second, third, fourth and fifth anniversaries of the date of the grant. If an option is not exercised within 10 years, it expires and the optionee loses all rights thereunder. The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | |||
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | |||
Vesting rights | The holder of the option has no rights as a shareholder until the option is exercised and shares have been issued. | |||
Percentage of outstanding stock maximum | 5% | |||
Policy for issuing shares upon exercise | The total number of stocks to be optioned to any optionee shall not exceed five per cent of the issued and outstanding common stocks on the date the option is granted. | |||
Cash received for options exercised | $ 6,000 | $ 9,000 | ||
Total intrinsic value of options exercised | $ 2,000 | $ 4,000 | ||
Exercise price range, lower range limit | $ / shares | $ 32.35 | $ 32.35 | ||
Exercise price range, upper range limit | $ / shares | $ 60.03 | $ 60.03 | ||
Fair value assumptions, method used | The Company uses the Black-Scholes valuation model to estimate the compensation expense related to its stock-based compensation and recognizes the expense over the vesting period on a straight-line basis. | |||
Share Unit Plans | ||||
Compensation cost recognized for employee and director | $ 2,000 | $ 2,000 | ||
Maximum aggregate number of common shares reserved for issuance | shares | 14.7 | |||
Stock Option Plan, Granted 2021 | First Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25% | |||
Stock Option Plan, Granted 2021 | Second Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25% | |||
Stock Option Plan, Granted 2021 | Third Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25% | |||
Stock Option Plan, Granted 2021 | Fourth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 25% | |||
Stock Option Plan, Granted 2022 | First Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20% | 20% | ||
Stock Option Plan, Granted 2022 | Second Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20% | 20% | ||
Stock Option Plan, Granted 2022 | Third Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20% | 20% | ||
Stock Option Plan, Granted 2022 | Fourth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20% | 20% | ||
Stock Option Plan, Granted 2022 | Fifth Anniversary | ||||
Stock option plan, Additional information | ||||
Vesting rights, percentage | 20% | 20% | ||
Share Unit Plans | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | The Company has DSU, PSU and RSU plans. The plans and the liabilities are marked-to-market at the end of each period based on an average common share price at the end of the period. | |||
Deferred Share Unit Plans | ||||
Share Unit Plans | ||||
Compensation cost recognized for employee and director | $ 2,000 | $ 6,000 | ||
Tax expense related to compensation costs for share units realized | 1,000 | 2,000 | ||
Deferred Share Unit Plans | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | 36,000 | 33,000 | ||
Deferred Share Unit Plans | Director | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | $ 37,000 | 34,000 | ||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | When short-term incentive awards are determined, the amount elected is converted to DSUs, which have a value equal to the market price of an Emera common share. When a dividend is paid on Emera’s common shares, each participant’s DSU account is allocated additional DSUs equal in value to the dividends paid on an equivalent number of Emera common shares. Following termination of employment or retirement, and by December 15 of the calendar year after termination or retirement, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by the average of Emera’s stock closing price for the fifty trading days prior to a given calculation date. Payments are made in cash. In addition, special DSU awards may be made from time to time by the Management Resources and Compensation Committee (“MRCC”), to selected executives and senior management to recognize singular achievements or by achieving certain corporate objectives. | |||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Executive and senior management | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | Under the executive and senior management DSU plan, each participant may elect to defer all or a percentage of their annual incentive award in the form of DSUs with the understanding, for participants who are subject to executive share ownership guidelines, a minimum of 50 per cent of the value of their actual annual incentive award (25 per cent in the first year of the program) will be payable in DSUs until the applicable guidelines are met. | |||
Deferred Share Unit Plans | Share Unit Plans | DSU Plan | Director | ||||
Share Unit Plans | ||||
Deferred share unit plan, description | Under the Directors’ DSU plan, Directors of the Company may elect to receive all or any portion of their compensation in DSUs in lieu of cash compensation, subject to requirements to receive a minimum portion of their annual retainer in DSUs. Directors’ fees are paid on a quarterly basis and, at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one Emera common share. When a dividend is paid on Emera’s common shares, the Director’s DSU account is credited with additional DSUs. DSUs cannot be redeemed for cash until the Director retires, resigns or otherwise leaves the Board. The cash redemption value of a DSU equals the market value of a common share at the time of redemption, pursuant to the plan. Following retirement or resignation from the Board, the value of the DSUs credited to the participant’s account is calculated by multiplying the number of DSUs in the participant’s account by Emera’s closing common share price on the date DSUs are redeemed. | |||
Performance Share Unit Plan | ||||
Stock option plan, Additional information | ||||
Award service period | 3 years | |||
Share Unit Plans | ||||
Tax expense related to compensation costs for share units realized | $ 3,000 | 5,000 | ||
Cash payments made during the year | 19,000 | 24,000 | ||
Performance Share Unit Plan | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | $ 41,000 | 40,000 | ||
Performance Share Unit Plan | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | Under the PSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. PSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. PSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional PSUs. The PSU value varies according to the Emera common share market price and corporate performance. PSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the PSU plan, grants may continue to vest in full and payout in normal course post-retirement. | |||
Compensation cost recognized for stock options | $ 11,000 | 18,000 | ||
Restricted Share Unit Plan | ||||
Stock option plan, Additional information | ||||
Award service period | 3 years | |||
Share Unit Plans | ||||
Tax expense related to compensation costs for share units realized | $ 3,000 | $ 2 | ||
Share Unit Plans: Aggregate intrinsic value | 32,000 | |||
Cash payments made during the year | $ 10,000 | |||
Restricted Share Unit Plan | Employee | ||||
Share Unit Plans | ||||
Share Unit Plans: Aggregate intrinsic value | 30,000 | |||
Restricted Share Unit Plan | Share Unit Plans | ||||
Stock option plan, Additional information | ||||
Share-based payment award, description | Under the RSU plan, certain executive and senior employees are eligible for long-term incentives payable through the plan. RSUs are granted annually for three-year overlapping performance cycles, resulting in a cash payment. RSUs are granted based on the average of Emera’s stock closing price for the fifty trading days prior to the effective grant date. Dividend equivalents are awarded and paid in the form of additional RSUs. The RSU value varies according to the Emera common share market price. RSUs vest at the end of the three-year cycle and the payouts will be calculated and approved by the MRCC early in the following year. The value of the payout considers actual service over the performance cycle and may be pro-rated in certain departure scenarios. In the case of retirement, as defined in the RSU plan, grants may continue to vest in full and payout in normal course post-retirement. | |||
Compensation cost recognized for stock options | $ 10,000 | $ 9,000 |
Stock-Based Compensation (Weigh
Stock-Based Compensation (Weighted Average Fair Values per Stock Option and Assumptions for Options Granted) (Details) - $ / shares | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Stock-Based Compensation [Abstract] | ||
Weighted average FV per option | $ 6.32 | $ 5.35 |
Expected term | 5 years | 5 years |
Risk-free interest rate | 3.53% | 1.79% |
Expected dividend yield | 5.05% | 4.55% |
Expected volatility | 20.07% | 18.87% |
Stock-Based Compensation (Summa
Stock-Based Compensation (Summary of Stock Option Information) (Details) - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Total Options, Number of Options | ||
Total Options: Number of Options, Exercised | (620,000) | (600,000) |
Non-Vested Options: Weighted average exercise price per share | ||
Non-Vested Options: Weighted average exercise price per share, Granted | $ 6.32 | $ 5.35 |
Stock option plan, Additional information | ||
Non-Vested options: Unrecognized compensation | $ 5 | $ 4 |
Non-vested options: Weighted average recognition period | 3 years | 3 years |
Vested Options: Weighted average remaining term | 5 years | 5 years |
Vested Options: Aggregate intrinsic value | $ 8 | $ 10 |
Vested Options: Fair value | $ 2 | $ 2 |
Employee Stock Option Plan | ||
Total Options, Number of Options | ||
Total Options: Number of Options, Outstanding, Beginning Balance | 2,853,879 | |
Granted | 483,100 | |
Total Options: Number of Options, Exercised | (146,475) | |
Total Options: Number of Options, Forfeited | (94,900) | |
Total Options: Number of Options, Outstanding, Ending Balance | 3,095,604 | 2,853,879 |
Total Options: Number of Options, Options exercisable | 1,842,349 | |
Total Options, Weighted average exercise price per share | ||
Total Options: Weighted average exercise price per share, Outstanding, Beginning Balance | $ 50.41 | |
Total Options: Weighted average exercise price per share, Granted | 54.64 | |
Total Options: Weighted average exercise price per share, Exercised | 43.94 | |
Total Options: Weighted average exercise price per share, Forfeited | 56.32 | |
Total Options: Weighted average exercise price per share, Outstanding, Ending Balance | 51.20 | $ 50.41 |
Total Options: Weighted average exercise price per share, Options exercisable | $ 48.39 | |
Non-Vested Options, Number of Options | ||
Non-Vested Options: Number of Options, Outstanding, Beginning Balance | 1,348,400 | |
Granted | 483,100 | |
Non-Vested Options: Number of Options, Vested | 526,620 | |
Non-Vested Options: Number of options, Forfeited | (51,625) | |
Non-Vested Options: Number of Options, Ending Balance | 1,253,255 | 1,348,400 |
Non-Vested Options: Weighted average exercise price per share | ||
Non-Vested Options: Weighted average exercise price per share, Outstanding, Beginning Balance | $ 4.08 | |
Non-Vested Options: Weighted average exercise price per share, Granted | 6.32 | |
Non-Vested Options: Weighted average exercise price per share, Vested | 3.58 | |
Non-Vested Options: Weighted average exercise price per share, Forfeited | 3.61 | |
Non-Vested Options: Weighted average exercise price per share, Outstanding, Ending Balance | $ 5.17 | $ 4.08 |
Stock-Based Compensation (Sum_2
Stock-Based Compensation (Summary of Activity Related to Employee and Director Deferred Share Units) (Details) - DSU Plan - Deferred Share Unit Plans | 12 Months Ended |
Dec. 31, 2023 $ / shares shares | |
Employee | |
Share Unit Plans: Units | |
Share Unit Plans: Outstanding, Beginning Balance | shares | 627,223 |
Share Unit Plans: Granted including DRIP | shares | 85,740 |
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares | 712,963 |
Share Unit Plans: Weighted Average Grant Date Fair Value | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares | $ 41.55 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares | 47.66 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares | $ 42.29 |
Director | |
Share Unit Plans: Units | |
Share Unit Plans: Outstanding, Beginning Balance | shares | 664,258 |
Share Unit Plans: Granted including DRIP | shares | 117,893 |
Share Unit Plans: Exercised | shares | (53,093) |
Share Unit Plans: Outstanding and exercisable, Ending Balance | shares | 729,058 |
Share Unit Plans: Weighted Average Grant Date Fair Value | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ / shares | $ 45.83 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | $ / shares | 49.99 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | $ / shares | 49.39 |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ / shares | $ 46.24 |
Stock-Based Compensation (Sum_3
Stock-Based Compensation (Summary of Activity Related to Employee Performance Share Units) (Details) - Performance Share Unit Plan - Employee - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Share Unit Plans: Units | ||
Share Unit Plans: Outstanding, Beginning Balance | 690,446 | |
Share Unit Plans: Granted including DRIP | 386,261 | |
Share Unit Plans: Exercised | (323,155) | |
Share Unit Plans: Forfeited | (10,187) | |
Share Unit Plans: Outstanding and exercisable, Ending Balance | 743,365 | |
Share Unit Plans: Weighted Average Grant Date Fair Value | ||
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ 56.24 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | 52.71 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | 54.62 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited | 55.15 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ 55.13 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 41 | $ 40 |
Stock-Based Compensation (Sum_4
Stock-Based Compensation (Summary of Activity Related to Employee Restricted Share Units) (Details) - Restricted Share Unit Plan - CAD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 32 | |
Employee | ||
Share Unit Plans: Units | ||
Share Unit Plans: Outstanding, Beginning Balance | 508,468 | |
Share Unit Plans: Granted including DRIP | 236,537 | |
Share Unit Plans: Exercised | (171,537) | |
Share Unit Plans: Forfeited | (10,827) | |
Share Unit Plans: Outstanding and exercisable, Ending Balance | 562,641 | |
Share Unit Plans: Weighted Average Grant Date Fair Value | ||
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding, Beginning Balance | $ 56.25 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Granted including DRIP | 52.07 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Exercised | 54.62 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Forfeited | 54.76 | |
Share Unit Plans: Weighted Average Grant Date Fair Value: Outstanding and exercisable, Ending Balance | $ 55.01 | |
Share Unit Plans: Aggregate intrinsic value | ||
Share Unit Plans: Aggregate intrinsic value | $ 30 |
Variable Interest Entities (Sum
Variable Interest Entities (Summary of Material Unconsolidated Variable Interest Entities) (Details) - NSPML - NSPML - CAD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Variable Interest Entity [Line Items] | ||
Equity Method Investment, Underlying Equity in Net Assets | $ 489 | $ 501 |
Maximum exposure to loss | $ 6 | $ 6 |